CANCELLED UNIFIED FACILITIES CRITERIA (UFC) CENTRAL STEAM BOILER PLANTS

CANCELLED  UNIFIED FACILITIES CRITERIA (UFC) CENTRAL STEAM BOILER PLANTS

UFC 3-430-02FA

15 May 2003

UNIFIED FACILITIES CRITERIA (UFC)

CENTRAL STEAM BOILER PLANTS

CANCELLED

APPROVED FOR PUBLIC RELEASE; DISTRIBUTION UNLIMITED

UFC 3-430-02FA

15 May 2003

UNIFIED FACILITIES CRITERIA (UFC)

CENTRAL STEAM BOILER PLANTS

Any copyrighted material included in this UFC is identified at its point of use.

Use of the copyrighted material apart from this UFC must have the permission of the copyright holder.

U.S. ARMY CORPS OF ENGINEERS (Preparing Activity)

NAVAL FACILITIES ENGINEERING COMMAND

AIR FORCE CIVIL ENGINEER SUPPORT AGENCY

Record of Changes (changes are indicated by \1\ ... /1/)

Change No. Date Location

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This UFC supersedes TM 5-810-15, dated 1 August 1995. The format of this UFC does not conform to UFC 1-300-01; however, the format will be adjusted to conform at the next revision. The body of this UFC is a document of a different number.

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UFC 3-430-02FA

15 May 2003

FOREWORD

\1\

The Unified Facilities Criteria (UFC) system is prescribed by MIL-STD 3007 and provides planning, design, construction, sustainment, restoration, and modernization criteria, and applies to the Military Departments, the Defense Agencies, and the DoD Field Activities in accordance with USD(AT&L) Memorandum dated 29 May 2002. UFC will be used for all DoD projects and work for other customers where appropriate. All construction outside of the United States is also governed by Status of forces Agreements (SOFA), Host Nation Funded Construction

Agreements (HNFA), and in some instances, Bilateral Infrastructure Agreements (BIA.)

Therefore, the acquisition team must ensure compliance with the more stringent of the UFC, the

SOFA, the HNFA, and the BIA, as applicable.

UFC are living documents and will be periodically reviewed, updated, and made available to users as part of the Services’ responsibility for providing technical criteria for military construction. Headquarters, U.S. Army Corps of Engineers (HQUSACE), Naval Facilities

Engineering Command (NAVFAC), and Air Force Civil Engineer Support Agency (AFCESA) are responsible for administration of the UFC system. Defense agencies should contact the preparing service for document interpretation and improvements. Technical content of UFC is the responsibility of the cognizant DoD working group. Recommended changes with supporting rationale should be sent to the respective service proponent office by the following electronic form: Criteria Change Request (CCR) . The form is also accessible from the Internet sites listed below.

UFC are effective upon issuance and are distributed only in electronic media from the following source:

• Whole Building Design Guide web site http://dod.wbdg.org/ .

Hard copies of UFC printed from electronic media should be checked against the current electronic version prior to use to ensure that they are current.

AUTHORIZED BY:

______________________________________

DONALD L. BASHAM, P.E.

Chief, Engineering and Construction

U.S. Army Corps of Engineers

______________________________________

DR. JAMES W WRIGHT, P.E.

Chief Engineer

Naval Facilities Engineering Command

KATHLEEN I. FERGUSON, P.E.

The Deputy Civil Engineer

DCS/Installations & Logistics

Department of the Air Force

______________________________________

Dr. GET W. MOY, P.E.

Director, Installations Requirements and

Management

Office of the Deputy Under Secretary of Defense

(Installations and Environment)

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TM 5-810-15

CHAPTER 1

INTRODUCTION

1-1. Purpose

Table 1-1. Central Steam Plant Sizes.

This manual provides guidance for the design of central steam plants for Army installations.

Category Size

1-2. Scope.

Small

Medium

Large

0-100,000 pph

100,000-300,000 pph

300,000-750,000 pph

This manual considers steam plants with capacities from one to three boilers, each rated between

20,000 and 250,000 pounds per hour (pph). Where special conditions and problems are not specifically covered in this manual, acceptable industry standards will be followed. Modifications or additions to existing systems solely for the purpose of meeting criteria in this manual are not authorized. The guidance and criteria herein are not intended to be retroactively mandatory. Clarification of the basic standards and guidelines for a particular application and supplementary standards which may be required for special cases may be obtained through normal channels from HQUSACE, WASH DC

20314-1000.

1-3. References.

Appendix A contains a list of references used in this manual.

1-4. Economic considerations.

selected during plant design to conform to this standard. This standard also requires quality engineering, equipment, and operations and maintenance personnel. In order for boilers to have high availability it is mandatory that a good water treatment program be implemented. Availability guarantees offered by boiler manufacturers for coal fired units are in the range of 85 to 90 percent and are in the range of 90 to 95 percent for gas fired boilers. A planned outage of a minimum of one day per year is normal for waterside inspection.

c. Maintenance. Steam plant arrangement will permit reasonable access for operation and maintenance of equipment. Careful attention will be given to the arrangement of equipment, valves, mechanical specialties, and electrical devices so that rotors, tube bundles, inner valves, top works,

The selection of one particular type of design for a given application, when two or more types of strainers, contactors, relays, and like items can be maintained or replaced. Adequate platforms, stairs, handrails, and kickplates will be provided so that design are known to be feasible, will be based on the results of an economic study.

operators and maintenance personnel can function conveniently and safely.

d. Future expansion. The specific site selected

1-5. Design philosophy.

a. General. Steam plants considered in this manual will be fired by gas, oil, gas-and-oil, coal, or waste fuels. Coal fired plants will use any combination of three commercially proven coal firing technologies. These include atmospheric cir-

CANCELLED stoker fired boilers. Stokers are designed to burn any one of the different types of anthracite, bituminous, sub-bituminous or lignite type coals.

ACFB boilers offer reduced sulfur dioxide emissuch as natural gas supply lines, coal and ash handling systems, coal storage, circulating water system, trackage, and access roads will be arranged insofar as practicable to allow for future expansion.

1-6. Design criteria.

a. General requirements. The design will provide for a steam plant which has the capacity to provide the quantity and type of steam required.

sions without use of scrubbers while firing a wide the plant equipment, building, and support facilities

b. Steam loads. The following information, as range of lower cost fuels such as high sulfur coal for the steam plant and the physical arrangement of applicable, is required for design: and waste fuels. To provide a quick scale for the (1) A forecast of annual and monthly diversiplants under review here, several categories have been developed, as shown in table 1-1.

b. Reliability. Steam plant reliability standards will be equivalent to a 1-day forced outage in 10 years with equipment quality and redundancy fied peak loads to be served by the project.

(2) Typical, seasonal, weekly and daily load curves and load duration curves of the load to be served. Figures 1-1 and 1-2 show example load duration curves.

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TM 5-810-15

1-2

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TM 5-810-15

(3) A forecast of peak loads encountered during the steam plant full mobilization.

(4) If the plant is to operate in conjunction with any existing steam generation on the base or is an expansion of an existing facility, the designer will also need the following:

(a) An inventory of major existing steam generation equipment giving principle characteristics such as type, capacities, steam characteristics, pressures and like parameters.

(b) Incremental thermal efficiency of existing boiler units.

(c) Historical operating data for each existing steam generating unit giving energy generated, fuel consumption, and other related information.

(5) Existing or recommended steam distribution systems to support base operations.

(6) A complete fuel analysis for each fuel being considered for use in the plant. Coal analyses shall include proximate analysis, ultimate analysis, grindability, higher heating value, ash analysis, ash fusion temperature, and agglomerating design is based on compliance coal, the design will include space and other required provisions for the installation of equipment. Boiler design will be control. ACFB boilers have low nitrogen oxide combustion temperatures. Selective noncatalytic reduction (SNCR) systems are now being required by several states even on ACFB boiler installations that are more stringent.

f. Waste disposal. Both solid and liquid wastes will be handled and disposed of in an environmentally acceptable manner. The wastes can be categorized generally as follows:

(1) Solid wastes. These include both bottom ash and fly ash from boilers.

(2) Liquid wastes. These include boiler blowdown, cooling tower blowdown, acid and caustic water treating wastes, coal pile runoff, and various contaminated wastes from chemical storage areas, sanitary sewage and yard areas.

classification.

(7) Plant site conditions must be identified to include ambient temperature ranges, maximum expected wind conditions, snow load, seismic conditions and any other site conditions that could affect the design of the boiler and its accessories.

g. Other environmental considerations. Other environmental considerations include noise control and aesthetic treatment of the project. The final location of the project within the site area will be reviewed in relation to its proximity to hospital and office areas and the civilian neighborhood, if

(8) Water quality available to the boiler to include such things as total dissolved solids, pH, etc.

(9) All codes that pertain to design, construction and placing of the boiler and its accessories into operation need to be identified.

(10) If any of the above data which is applicable. Also, the general architectural design will be reviewed in terms of coordination and blending with the style of surrounding buildings.

Any anticipated noise or aesthetics problem will be resolved prior to the time that final site selection is required for performing the detailed design is unavailable, the designer will develop this data.

approved.

h. Construction cost estimate. The following items should be considered in the construction cost estimate for a boiler plant.

c. Fuel source and cost. The type, availability, and cost of fuel will be determined in the early

(1) Substructure

(2) Structural Steel stages of design, taking into account environmental regulatory requirements that may affect fuel and fuel characteristics of the plant.

d. Water supply. Fresh water is required for the boiler cycle makeup. Quantity of makeup will vary

(3) Superstructure

(4) Painting

(5) Coal, Limestone, Inert Bed Material &

(6) Stack Foundations with the type of boiler plant, amount of condensate return for any export steam, and the maximum heat rejection from the cycle.

e. Stack emissions. A steam plant will be designed for the type of stack gas cleanup equipment which meets federal, state, and local emission requirements. For a coal fired boiler, this will involve an electrostatic precipitator or baghouse for particulates or fly ash removal, and a scrubber for flue gas desulfurization (FGD) unless fluidized bed combustion or compliance coal is employed. If tions

(7) Air Pollution Control Equipment Founda-

(8) Roads, Grading & Site Improvements

(9) Ash Pond, Coal Runoff Pond & Coal Pile

Stabilization

(10) Railroad Siding

(11) Water & Sewers

(12) Fencing

(13) Steam Generators

(14) Particulate Control Equipment

(15) Sulfur Removal Equipment

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TM 5-810-15

(16) Stacks ment

(17) Continuous Flue Gas Monitoring Equip-

(18) Coal Handling System

(19) Limestone Handling System

(20) Inert Bed Handling System

(21) Ash Handling System

(22) Panels, Instruments & Controls

(23) Water Treatment Equipment

(24) Deaerators

(25) Feedwater Heaters

(26) Boiler Feed Pumps

(27) Fire Protection

(28) Air Compressors

(29) Power Piping

(30) Electrical Equipment

(31) Power Wiring

(32) Plant Substation

(33) Operator Training

(34) Fuels

(35) Chemicals

(36) Fuel Storage

1-7. Explanation of abbreviations and terms.

Abbreviations and special terms used in this regulation are explained in the glossary.

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TM 5-810-15

CHAPTER 2

STEAM PLANT LOCATION, SITE DEVELOPMENT AND PLANT STRUCTURES

2-1. General.

Each potential plant site will be evaluated to determine which is the most economically feasible for the size of plant being considered.

a. Steam plant location. The process of evaluating and selecting a possible steam plant site must include the following activities. Identify region of interest. Apply exclusionary criteria to eliminate unsuitable areas within region of interest. Identify candidate sites. Prepare site specific layouts and conduct conceptual engineering studies of the candidate site. Rank candidate sites, based on analyses.

Select most suitable site.

(1) The evaluations of candidate sites are performed by specialists from the fields of environmental engineering, biology/ecology, ground and surface water hydrology, geology and seismology, soils and foundation engineering, meteorology, demography, land use and zoning, sociology and economics, system planning, and law.

(2) Selection of the site will be based on the availability of usable land for the plant, including yard structures, fuel handling facilities, and any future expansion. Other considerations that will be taken into account in site selection are: soil information, site drainage, wind date, seismic zone, and ingress and egress. For economic purposes and operational efficiency, the plant site will be located as close to the load center as environmental

c. Waste material control. State regulations control disposal of coal ash and FGD wastes and the selection of landfill site.

2-3. Water supply.

a. General requirements. Water supply should be adequate to meet present and future plant requirements. The supply may be available from a local municipal or privately owned system, or it may be necessary to utilize surface or subsurface sources.

(1) Plant requirements must be estimated for all uses, including feedwater makeup, auxiliary cooling, ash transport, coal dust suppression, fire protection, and domestic uses.

(2) Provide backflow preventer upstream of water treatment, ash handling equipment, FGD system and hose bibbs.

b. Quality. Water quality and type of treatment required will be compatible with the type of plant to be built. Surface and groundwater sources must be evaluated for sufficient quantity and quality.

c. Water rights. If water rights are required, it will be necessary to insure that an agreement for water rights provides sufficient quantity for present and future use.

d. Water wells. If the makeup to the closed system is from water wells, a study to determine water table information and well drawdown will be required. If this information is not available, test conditions permit.

b. Lead time. The amount of lead time necessary to perform the studies, and to submit the required environmental impact statements should also be well studies must be made.

e. Once through system. If the plant has a once through cooling system, the following will be determined: considered in site selection, since this lead time will vary from site to site. Environmentally sensitive areas will probably require lengthier studies, delaying construction. If steam load demands must be met within a limited time period, this factor

(1) The limitations established by the appropriate regulatory bodies which must be met to obtain a permit required to discharge heated water

(2) Maximum allowable temperature rise becomes more important. Generally, the lead time interval should be 18 to 24 months.

2-2. Environmental regulations.

permissible as compared to system design parameters. If system design temperature rise exceeds permissible rise, a supplemental cooling system (cooling tower or spray pond) must be

a. Air quality control. Central steam boiler plants must meet current Federal, State and local regulations.

b. Water quality control. Waste water must comply with current regulations including discharge of free available chlorine (FAG), pH, total suspended solids (TSS), oil/grease, copper (Cu), iron (Fe), polychlorinated biphenyl (PCB), and heat.

incorporated into the design.

(3) Maximum allowable temperature for river or lake after mixing of cooling system effluent with source. If mixed temperature is higher than allowable temperature, a supplemental cooling system must be added. It is possible to meet the conditions of (2) above and not meet the conditions in this subparagraph.

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TM 5-810-15

(4) If extensive or repetitive dredging of waterway will be necessary for plant operations.

(5) The historical maximum and minimum water level and flow readings. Check that adequate water supply is available at minimum flow and if site will flood at high level.

2-4. Site development.

a. Soils investigation. An analysis of existing soils conditions will be made to determine the proper type of foundation. Soils data will include elevation of each boring, water table level, description of soil strata including the group symbol based on the Unified Soil Classification System, and penetration data (blow count). Geological conditions must support the foundations of plant structures at a reasonable cost with particular attention being paid to bedrock formations and faults. The soils report will include recommendations as to type of foundations for various purposes; excavation, dewatering and fill procedures; and suitability of on site material for fill and earthen dikes including data on soft and organic materials, rock and other pertinent information as applicable.

b. Grading and drainage.

(1) Basic criteria. Determination of final grading and drainage scheme for a new steam plant will be based on a number of considerations including size of property in relationship to the size of plant facilities, desirable location on site, and plant access based on topography.

(2) Drainage. Storm water drainage will be evaluated based on rainfall intensities, runoff characteristics of soil, facilities for receiving storm water discharge, and local regulations.

of the coal pile and methods of stockout and reclaim will further affect space requirements. If oil is used as primary fuel or as a backup fuel, storage tank space must be calculated.

(2) Space for the disposal of wet and dry ash will be provided.

(3) Control of runoff from material storage areas is required by EPA regulations. Space for retention ponds must be provided.

e. Flood protection. Site protection for flood frequency of once every 500 years will be calculated into area requirements.

f. Other requirements. Space for parking, warehouses, cooling water systems, environmental systems, construction laydown areas and other requirements will be provided.

2-5. Plant access.

a. Plant roadway requirements. Layout of plant roadway will be based on volume and type of traffic, speed, and traffic patterns. Proximity to principle highways should permit reasonably easy access for construction crews and deliveries. Roadway design will be in accordance with American

Association of State Highway and Transportation

Officials (AASHTO) standard specifications. Roadway material and thickness will be based on economic evaluations of feasible alternatives. Vehicular parking for plant personnel and visitors will be located in areas that will not interfere with the safe operation of the plant. Turning radii will be adequate to handle all vehicle categories.

b. Railroads. If a railroad spur is selected to handle fuel supplies and material and equipment deliveries during construction or plant expansion, the design will be in accordance with American

Railway Engineering Association (AREA) Manual.

(3) Erosion prevention. All graded areas will

(1) Spur layout will accommodate coal hanbe stabilized to control erosion by designing shaldling facilities including a storage track or loop low slopes to the greatest extent possible and by track for empty cars. Refer to chapter 5 for means of soil stabilization such as seeding, sod, stone, riprap and retaining walls.

c. Meteorology. Precipitation, wind conditions, evaporation, humidity and temperature will affect

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d. Area requirements. Plant area requirements will be figured on the type of plant; capacity; urban, additional information.

(2) If liquid fuel is to be handled, unloading pumps and steam connections for tank car heaters may be required in frigid climates.

2-6. Plant structures.

a. Size and arrangements. The steam plant main building size and arrangement depend on the suburban or rural location; design of fuel storage selected plant equipment and facilities including: and handling facilities; disposal of soil waste and whether steam generators are indoor or outdoor treatment of wastewater; condenser cooling; and type; coal bunker or silo arrangement in the cases the plant structure and miscellaneous requirements.

of pulverized coal and stoker fired plants; coal,

Acquisition of land should include plant access limestone and inert bed silo arrangement in the case roads, rail access and space for future additions to of atmospheric circulating fluidized bed (ACFB) the plant.

boiler plants; source of cooling water supply

(1) Space must be provided for the long relative to the plant; provisions for future term coal storage pile. Maximum allowable height expansion; and aesthetic and environmental con-

TM 5-810-15

siderations. Generally, the main building will consist of: a steam generator bay (or firing aisle the semi-outdoor units); an auxiliary bay for feedwater heaters, pumps, and switchgear; and general spaces as may be required for machine shop, locker room, laboratory and office facilities. For very mild climates the steam generators may be outdoor type

(in a weather protected, walk-in enclosure) although this arrangement presents special maintenance problems. If incorporated, the elevator will have access to the highest operating level of the steam generator (drum levels).

loads for steam plant floors are as follows:

Basement and operating floors

Mezzanine, deaerator, and miscellaneous

operating floors

Office, laboratories, instrument shops,

and other lightly loaded areas

200 psf

200 psf

100 psf

Live loads for actual design will be carefully reviewed for any special conditions and actual loads applicable.

(2) Live loads for equipment floors will be based on the assumption that the floor will be

b. Layout considerations. The layout of the utilized as laydown for equipment parts during structural system will identify specific requirements maintenance. Load will be based on heaviest piece relative to vertical and horizontal access, personnel removed during maintenance.

needs and convenience, equipment and respective

(3) Live load assumptions will be in accordmaintenance areas, floors and platforms.

ance with TM 5-809-1.

c. Soil investigation requirements. A subsurface

g. Other loads. In addition to the live and dead exploration program will be conducted. Design loads, the following loadings will be provided for: information regarding the interaction of the struc-

(1) Piping load. Weight of major piping ture and the surrounding ground is required. In sized and routed will include weight of pipe, addition, an investigation should furnish informainsulation, hydraulic weight (pipe full of water) in tion as to the source of construction materials and addition to any shock loads. Pipe hanger loads will the types and extent of materials which will be be doubled for design of supporting steel. In encountered during construction will be investicongested piping areas increase live load on the gated. Information required for design includes: supporting floor by 100 pounds per square foot extent of each identifiable soil stratum, depth to top

(psf). Structural steel will be provided to of rock and character of the rock, elevation of adequately support all mechanical piping and normal ground water at site, and engineering electrical conduit. Provision will be made to properties of the soil and rock.

accommodate expansion and contraction and

d. Foundation design. Selection of the type of drainage requirements of the pipe. Piping foundation to be used for each component of the connections must be made to preclude rupture plant (i.e., main building, boiler, stacks and coal under the most adverse conditions expected. Pipe handling structure) will be determined from the supports will be close coupled to supporting strucsubsurface exploration data, cost considerations tures when the more severe seismic conditions are and availability of construction trades.

expected.

e. Structural design. Thermal stations will be designed utilizing conventional structural steel for the main steam station building. Separate structural steel will be provided to support building floors and platforms; boiler steel will not be used in support building structure. The pedestal for supporting the

CANCELLED masonry construction may be used for the building framing (not for boiler framing); special concrete inserts or other provisions must be made in such load assumptions will be in accordance with TM 5-

809-1.

(3) Seismic loading. Buildings and other structures will be designed to resist seismic loading in accordance with the zone in which the building is located. Seismic design will be in accordance with

TM 5-809-10.

event for support of piping, trays and conduits. An the site on all surfaces exposed to the wind. Wind

(4) Equipment loading. Equipment loads are economic evaluation will be made of these to resist the horizontal wind pressure available for furnished by the various manufacturers of each alternatives.

(2) Wind loading. Building will be designed equipment item. In addition to equipment dead

f. Structure loading.

(1) Buildings, structures and all portions thereof will be designed and constructed to support all live and dead loads without exceeding the allowable stresses of the selected materials in the structural members and connections. Typical live loads, impact loads, short circuit forces for generators, and other pertinent special loads prescribed by the equipment function or requirements will be included. Dead load assumptions will be in accordance with TM 5-809-1. Ductwork, flue gas breeching, stacks, and other hot equipment must be

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TM 5-810-15

supported such that expansion and contraction will not impose detrimental loads and stresses on related structures.

(5) Snow loading. Snow load assumptions will be in accordance with TM 5-809-1.

h. Architectural treatment.

(1) The architectural treatment will be developed to harmonize with the site conditions, both natural and manmade. Depending on location, the environmental compatibility may be the determining factor. In other cases the climate or user preference, tempered with aesthetic and economic factors, will dictate architectural treatment.

(2) For special circumstances, such as areas where extended periods of very high humidity, frequently combined with desert conditions giving rise to heavy dust and sand blasting action, indoor construction with pressurized ventilation will be required.

(3) Control rooms, offices, locker rooms, and some outbuildings will be enclosed regardless of enclosure selected for main building.

(4) Equipment room size will provide adequate space for equipment installation, maintenance and removal. A minimum of aisle space between items will be 4 feet if feasible.

Provide a minimum of 8 feet clearance between boilers 60,000 pph and larger. If future expansion is planned, size of room will be based on future requirements. Equipment room construction will

i. Special considerations.

(1) Crane bay-provide removable openings in floor above major equipment for removal by station crane (if provided).

(2) Provide hoists and supports for maintenance on pumps, fans and other heavy equipment.

Provide a beam into the plant to hoist equipment to an upper level.

(3) All anchor bolts for equipment will be sleeved to allow adjustment for final alignment of equipment.

2-7. Heating, ventilating and air conditioning systems (HVAC).

a. General. System analysis and design procedures provided in the American Society of Heating,

Refrigeration and Air Conditioning Engineers

(ASHRAE) Guide for Data books and TM 5-810-1 should be followed, unless otherwise stated or specifically directed by other criteria.

b. Design considerations. When a computer program is required, provisions for showing an estimate of the hourly space heating and cooling requirements, and hourly performance of the heating and cooling system can be structured. When manual computation is used, the heating and cooling load estimates will be in accordance with the current edition of the ASHRAE Handbook of

Fundamentals.

allow for equipment removal and include double

2-8. Drainage.

doors and steel supports for chain hoists. Adequate

a. Drains which may contain coal or oil will have ventilation and heating will be included.

suitable separators to separate coal or oil from

Attenuation of noise will be considered in room drainage before being connected to sewer lines.

design.

b. Provide drains and connect to storm water

(5) Provide openings or doorways for drainage system for diked areas for above ground passage of the largest equipment units. Make oil storage.

openings for ventilation louvers, breechings, and

c. Maximum temperature of effluent to the drain piping where necessary. Fire doors, fire shutters or system will be as required by governing codes. A a combination of both, may be required.

(6) On multiple floor installations, provide a freight elevator.

(7) Furnish necessary shower room, toilet

CANCELLED contain a sampling laboratory space, storage area, small repair area, control room (in larger plants), generator room, lunch room, compressor room, temperature regulating valve will be used to inject potable water into the high temperature waste stream from the blowdown tank. This technique will also be used on other equipment as required.

2-9. Plant design safety.

a. Introduction. The safety features described in the following paragraphs will be incorporated into the steam plant design to assist in maintaining a chemical storage area, office space for supervisors high level of personnel safety.

and clerks. Parking spaces for plant personnel and

b. Design safety features. In designing a steam visitors should be provided near the boiler plant.

plant, the following general recommendations on

(8) Finish of plant interior walls and tunnels safety will be given attention: will have a coating which will permit hose down or

(1) Equipment will be arranged with scrubbing of areas.

adequate access space for operation and for

(9) Concrete will be in accordance with TM maintenance.

5-805-1, American Concrete Institute (ACI) 318 and 301.

Wherever possible, auxiliary equipment will be arranged for maintenance handling by monorails, wheeled trucks, or portable A-frames if disassembly of heavy pieces is required for maintenance.

(2) Safety guards will be provided on moving or rotating parts of all equipment.

(3) All valves, specialties, and devices needing manipulation by operators will be accessible without ladders, and preferably without using chain-wheels.

(4) Valve centers will be mounted approximately 7 feet above floors and platforms so that rising stems and bottom rims of handwheels will not be a hazard. Provide access platforms for operations and maintenance of all valves and equipment over 7 feet above the floor.

(5) Stairs with conventional riser-tread proportions will be used. Vertical ladders should be installed only as a last resort.

(6) All floors, gratings and checkered plates will have nonslip surfaces.

(7) No platform or walkway will be less than

30-inches wide.

(8) Toe plates, fitted closely to the edge of all floor openings, platforms and stairways, will be provided in all cases. Handrails will be provided on platforms and floor openings.

(9) Not less than two exits will be provided from catwalks, platforms longer than 10 to 15 feet in length, boiler aisles, floor levels and the steam plant. Emergency lighting will be provided for all modes of egress.

(10) All floors subject to washdown or leaks

TM 5-810-15

will be sloped to floor drains.

(11) All areas subject to lube oil or chemical spills will be provided with curbs and drains.

(12) If plant is of semioutdoor or outdoor construction in a climate subject to freezing weather, weather protection will be provided for critical operating and maintenance areas such as the firing aisle, boiler steam drum ends and soot blower locations.

(13) Adequate illumination will be provided throughout the plant. Illumination will comply with requirements of the Illuminating Engineers Society

(TES) Lighting Handbook.

(14) Comfort air conditioning will be provided throughout control rooms, laboratories, offices and similar spaces where operating and maintenance personnel spend considerable time.

(15) Mechanical supply and exhaust ventilation will be provided for all of the steam plant equipment areas to alleviate operator fatigue and prevent accumulation of fumes and dust.

(16) Noise level will be reduced to at least the recommended maximum levels of OSHA. Use of fan silencers, compressor silencers, mufflers on internal combustion engines, and acoustical material is required as discussed in TM 5-805-4 and TM

5-805-9.

(17) Color schemes will be psychologically restful except where danger must be highlighted with special bright primary colors.

(18) Each equipment item will be clearly labeled in block letters identifying it both by equipment item number and name.

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TM 5-810-15

CHAPTER 3

STEAM GENERATORS

3-1. Introduction.

3-2. Boiler design.

a. General. This chapter addresses the design requirements for gas, oil, coal, and waste fuel fired steam generating, water-tube boilers and components with steam capacities between 20,000 and

250,000 pph and maximum pressures of 450 pounds per inch gauge (psig)/saturated and 400 psig/700 degrees F superheated.

b. New combustion technologies. The only major development in combustion technology in the past seventy years has been fluidized bed combustion.

(1) History. Earlier fluidized bed technologies included the bubbling bed boiler.

Bubbling bed boiler efficiency is similar to that of a stoker boiler (80 to 82 percent). Atmospheric circulating fluidized bed (ACFB) boiler efficiency is comparable to pulverized coal boiler efficiency

(86 to 88 percent). Bubbling bed boilers are not included in this manual not only because they are less fuel efficient, but also because they are inferior to ACFB units in the areas of sorbent utilization, emissions reductions and fuel flexibility.

(2) Advantages. Fluidized bed boilers have gained acceptance in the industrial and utility sectors by providing an economical means of using a wide range of fuels while meeting emissions requirements without installing flue gas desulfurization systems, such as wet and dry type scrubbers.

(3) Emission reductions. Sulfur capture is accomplished by injecting a sorbent, such as limestone or dolomite into the furnace along with coal and other solid fuels. Storage and handling of limestone must be included. Optimum sulfur cap-

a. Design. Boilers will be designed and constructed in accordance with Section 1 of the American Society of Mechanical Engineers (ASME)

Boiler and Pressure Vessel Code.

b. Type. The boilers are to be natural circulation and two drum design. Coal fired boilers are balanced draft and gas/oil fired boilers are forced draft.

3-3. Boiler construction options.

a. Construction types. The specific type of boiler construction will depend on the boiler size, type of firing and life cycle costs. Three boiler construction types are available: shop assembled package units, field assembled modular units and field erected units.

b. Package units. Package units are completely assembled before leaving the boiler manufacturer

*s factory. For this reason, the quality of workmanship is generally better and the field installation costs are considerably lower than for the modular and field erected units. Package units covered by this manual are limited to stoker fire boilers with steam capacities of approximately 50,000 pph and below, and gas and/or oil fired units of approximately 200,000 pph and below.

c. Modular units. Modular units are too large for complete shop assembly. Some of the components, such as the boiler furnace, superheater, boiler tube bank and economizer and air heater are assembled in the manufacturer

*s shop prior to shipment for final erection at the field site. Modular units should x emissions are achieved by maintaining a combusmanufacturing plant conditions. Since component assembly has taken place in the manufacturer

*s tion temperature at approximately 1550 degree F which is lower than other coal firing technologies.

CANCELLED

(4) Unique components. Atmospheric fluidized bed (ACFB) boilers in addition to having components which are common to other shop, the field manhour erection time will be reduced. Modular units are limited to stoker fired boilers ranging in steam capacity from approximately 50,000 to 150,000 pph.

d. Field erected units. Field erected boilers have numerous components, such as the steam drum, the combustion technologies (superheater, airheater, be subject to better quality control due to lower (mud) drum, furnace wall panels, superheater steam coil air preheater, economizer, sootblowers, sections, generating tube banks, economizer and air etc.), ACFB boilers have unique components. The heater plus flue gas and air duct sections which are following list of unique ACFB boiler components assembled at the job site. Therefore, they take is described in more detail in individual sections longer to install than either a package or a modular later in this chapter: lower combustor, upper type unit. Field erected units are available from combustor and transition zone, solids separator, about 40,000 to 250,000 pph and, if required, solids reinjection device, and external heat much larger. Field erected stoker fired boilers are exchanger (optional).

available in this size range, and pulverized coal

3-1

3-2

TM 5-810-15

fired units may be specified for boilers with capacities of 100,000 pph and above. Field erected atmospheric circulating fluidized bed boilers

(ACFB) are 80,000 pph or larger. Gas and oil fired boilers and field erected for capacities of 200,000 pph or larger. Field erected units are the only boilers available for any of these technologies above 200,000 pph.

3-4. Available fuels.

a. Natural gas. Natural gas is the cleanest burning of the widely used commercially available fuels. It contains virtually no ash which reduces design, building and operating costs. This also eliminates the need for particulate collection equipment such as baghouses or electrostatic precipitators. Thorough mixing with combustion air allows low excess air firing. The high hydrogen content of natural gas compared to the oil or coal causes more water vapor to be formed in the flue gas. This water takes heat away from the combustion process, making less heat available for steam generation which lowers the boiler efficiency.

b. Natural gas analysis. Two types of analyses of natural gas are commonly used. Proximate analysis provides the percentage content by volume of methane, ethane, carbon dioxide and nitrogen.

Ultimate analysis provides the percentage content by weight of hydrogen, carbon, nitrogen and oxygen. Table 3-1 gives natural gas analyses from selected United States fields.

c. Fuel oil. Compared to coal fuel oils are relatively easy to handle and burn. Ash disposal and emissions are negligible. When properly atomized oil characteristics are similar to natural gas. Even though oil contains little ash, other constituents such as sulfur, sodium and vanadium present problems. These concerns include emission of pollutants, external deposits and corrosion.

d. Fuel oil analysis. Historically petroleum refineries have produced five different grades of fuel oil. Fuel oils are graded according to gravity and viscosity as defined by ASTM standard specifications with No. 1 being the lightest and No. 6 being the heaviest. Table 3-2 lists typical analyses of the various grades.

e. Coal types. For the purpose of boiler design, domestic U.S. coals are divided into four basic classifications: lignite, subbituminous, bituminous, and anthracite. Anthracite, however, requires special furnace and burner designs due to its low volatile content and is not normally used in the U.S.

for boiler fuel. Note the following illustrations, figures 3-1 and 3-2. In general, these coal classifications refer to the ratio of fixed carbon to volatile matter and moisture contained in the coal, which increases with the action of pressure, heat, and other agents over time as coal matures. The changes in this ratio over the stages of coal information are illustrated in figure 3-3. Volatile matter consists of hydrocarbons and other compounds which are released in gaseous form when coal is heated. The amount present in a particular coal is related to the coal

*s heating value and the rate at which it burns. The volatile matter to fixed carbon ratio greatly affects boiler design, since the furnace dimensions must allow the correct retention time to properly burn the fuel.

Table 3-1. Analyses of Natural Gas from Selected United States Fields.

Pittsburg So. Cal.

Birmingham Kansas City

Proximate, % by Volume

83.40

100.00

84.00

100.00

90.00

100.00

84.10

Methane CH

4

Ethane C H

6

Carbon D.C0

2

Nitrogen N

2

Total

Ultimate % by Weight

Hydrogen H

2

Carbon C

15.80

0.80

100.00

14.80

0.70

0.50

100.00

5.00

5.00

100.00

6.70

0.80

8.40

100.00

16.00

6.50

25.53

75.25

1.22

23.30

74.72

0.76

1.22

22.68

69.26

8.06

20.85

64.84

12.90

1.41

100.00

20.35

69.28

10.37

Nitrogen N

2

Oxygen 0

2

Total 100.00

77.50

100.00

Sp Gr (Air= 1.0)

Btu/lb

Fuel lb/10,000 Btu

Theoretical Air lb/10,000 Btu

Total Moisture lb/10,O00 Btu

0.610

1,129

23,170

0.432

7.18

0.915

0.636

1,116

22,904

0.437

7.18

0.917

0.600

1,000

21,800

0.459

7.50

0.971

0.630

974

20,160

0.496

7.19

0.933

0.697

1,073

20,090

0.498

7.18

0.911

*At 60 degree F and 30 in. Hg

Los Angeles

Weight, %

Sulfur

Hydrogen

Carbon

Nitrogen

Oxygen

Ash

Gravity

Deg API

Specific

Lb per gal

Pour Pt,F

Viscosity

Centistokes, 100 F

SSU @100 F

SFS @ 122 F

Water & Sediment,

Vol %

Heating Value

Btu/lb, gross

(Calculated)

*Estimated

TM 5-810-15

Table 3-2. Range of Analyses of Fuel Oils.

No. 1

0.01-0.5

13.3-14.1

85.9-6.7

0-0.1

No. 2

0.05-1.0

11.8-13.9

86.1-88.2

0-0.1

No. 4

0.2-2.0

(10.6-13.0)*

(86.5-89.2)*

0-0.10

40-44

0.825-0.806

6.87-6.71

0 to-50

1.4-2.2

28-40

0.887-0.825

7.39-6.87

0 to -40

1.9-3.0

32-40

0-0.1

15-30

0.966-0.876

8.04-7.30

-10 to +50

10.5-65

60-300

0-1.0

No. 5

0.5-3.0

(10.5-12.0)*

(86.5-89.2)*

0-0.10

No. 6

0.7-3.5

(9.5-12.0)*

(86.5-90.2)*

0.01-0.50

14-22

0.972-0.922

8.10-7.68

-10 to +80

65-200

20-40

0.05-1.0

7-22

1.022-0.922

8.51-7.68

+15 to +85

260-750

45-300

0.05-2.0

19,670-19,860 19,170-19,750 18,280-19,400 18,100-19,020 17,410-18,990

CANCELLED

3-3

TM 5-810-15

f. Coal analysis. Two analyses of coal are commonly used to determine the classification and constituents of coal: proximate analysis and ultimate analysis. Proximate analysis provides the peror sold. If sulfur capture is not required then another maufacturer recommended inert material such as sand may be used. ACFB fuel flexibility includes the following list of potential fuels— centage content by weight of fixed carbon, volatile matter, moisture, and ash, and the heating value in

Btu per pound. These classifications are shown in table 3-3. Ultimate analysis provides the percentage

(1)

(2)

(3)

(4)

Anthracite coal

Anthracite culm

Bark and woodwaste

Bituminous coal content by weight of carbon, hydrogen, nitrogen, oxygen, and sulfur. These data are used to determine air requirements and the weight of combustion by-products, both of which are used to determine boiler fan sizes. Table 3-4 lists coal and

(5) Bituminous gob

(6) Gasifier char

(7) Industrial sludges, wastes, residues

(9) Municipal refuse ash analysis together, ash fusion temperatures and other data needed by boiler manufacturers for the design and guarantee of boiler performance.

g. Alternate ACFB boiler fuels. ACFB systems when properly designed can burn a wide variety of materials that contain carbon. Many can be utilized by themselves, while others are limited to a certain percentage of total heat input as part of a mixture with another fuel. Fuels with sulfur are burned in combination with a calcium rich material such as dolomite or limestone. Sulfur is removed as calcium sulfate in the baghouse and either landfilled

(10) Oil

(11) Oil shale

(12) Paper products waste

(13) Peat

(14) Petroleum coke

(15) Phenolic resins

(16) Plastics

(17) Sewage sludge

(18) Subbituminous coal

(19) Textile waste

(20) Shredded tires

3-4

TM 5-810-15

MD

MI

MO

MO

ND

IN

KS

KY

KY

State Rank

AL F

IA

IL

IL

AR

AR

CO

CO

CO

H

G

H

C

D

B

F

1

F

G

J

D

H

H

F

F

G

Table 3-3. Analysis of Typical U.S. Coals. (As Mined)

Btu/lb

14,210

13,700

13,700

13,720

13,210

10,130

11,420

12,670

14,290

12,080

13,870

11,860

12,990

11,300

7,210

3.2

12.4

5.4

10.5

34.8

% Proximate Analysis

VM FC Ash

5.5

30.8

60.9

2.8

2.1

3.4

2.5

1.4

19.6

9.8

16.2

5.7

32.6

30.5

78.8

71.8

83.8

54.3

45.9

9.3

8.6

8.0

11.7

4.0

18.2

35.0

32.1

32.0

28.2

70.4

47.0

53.5

44.6

30.8

8.2

5.6

9.0

12.9

6.2

% Ultimate Analysis

C H

2

S O

2

N

2

5.5

80.3

4.9

0.6

4.2

1.7

2.1

3.4

2.5

1.4

19.6

80.3

79.6

83.9

73.4

58.8

3.4

3.9

2.9

5.1

3.8

1.7

1.0

0.7

0.6

0.3

1.7

1.8

0.7

6.5

12.2

1.5

1.7

1.3

1.3

1.3

10,720

12,130

11,480

14.1

8.0

12.1

35.6

33.0

40.2

39.3

50.6

39.1

11.0

8.4

8.6

14.1

8.0

12.1

58.5

68.7

62.8

4.0

4.5

4.6

4.3

1.2

4.3

7.2

7.6

12.4

7.4

3.1

7.5

36.6

31.8

35.0

37.7

42.3

52.4

58.9

45.3

8.7

8.4

3.0

9.5

12.4

7.4

3.1

7.5

3.2

12.4

5.4

10.5

34.8

63.4

70.7

79.2

66.9

79.0

65.8

71.6

63.4

42.4

4.3

4.6

5.4

4.8

4.1

4.5

4.8

4.2

2.8

2.3

2.6

0.6

3.5

1.0

2.9

3.6

2.5

0.7

6.6

7.6

5.0

7.2

6.4

2.9

7.4

4.2

5.2

12.4

0.9

1.6

1.0

1.3

1.3

1.5

1.4

1.6

1.4

1.4

1.3

0.7

3-5

3-6

TM 5-810-15

Table 3-3. Analysis of Typical U.S. Coals. (As Mined) (Continued).

State Rank

NM

NM

B

F

OH

OH

OK

OK

F

G

D

F

PA*

PA**

B

B

PA*** B

PA C

PA

PA

E

F

RI

TN

A

F

TX

TX

UT

F

J

F

VA

VA

VA

C

E

F

Btu/lb

13,340

12,650

12,990

12,160

13,800

13,630

11,950

13,540

12,820

13,450

14,310

13,610

9,313

13,890

12,230

7,350

12,990

11,850

14,030

14,510

5.4

2.3

4.9

3.0

3.3

2.6

13.3

1.8

4.0

33.7

4.3

3.1

3.1

2.2

% Proximate Analysis

VM FC Ash

2.9

2.0

5.5

33.5

82.7

50.6

8.9

13.9

4.9

8.2

2.6

2.1

36.6

36.1

16.5

35.0

51.2

48.7

72.2

57.0

7.3

7.0

8.7

5.9

3.8

3.1

3.7

8.4

20.5

30.0

2.5

35.9

48.9

29.3

37.2

10.6

21.8

36.0

77.1

87.7

82.2

78.9

70.0

58.3

65.3

56.1

34.9

29.7

51.8

66.7

67.9

58.0

13.7

6.9

9.2

9.7

6.2

9.1

18.9

6.2

12.2

7.3

6.7

19.6

7.2

3.8

5.4

2.3

4.9

3.0

3.3

2.6

13.3

1.8

4.0

33.7

43.0

3.1

3.1

2.2

% Ultimate Analysis

C H

2

S O

2

N

2

2.9

2.0

82.3

70.6

2.6

4.8

0.8

1.3

1.3

6.2

1.2

1.2

4.9

8.2

2.6

2.1

71.9

68.4

80.1

76.7

4.9

4.7

4.0

4.9

2.6

1.2

1.0

0.5

7.0

9.1

1.9

7.9

1.4

1.4

1.7

2.0

76.1

86.7

81.6

80.2

80.7

76.6

64.2

77.7

65.5

42.5

72.2

70.5

80.1

80.6

1.8

1.9

1.8

3.3

4.5

45.9

0.4

5.2

5.9

3.1

5.1

3.2

4.7

5.5

0.6

0.5

0.5

0.7

1.8

1.3

0.3

1.2

2.0

0.5

1.1

0.6

1.0

0.7

1.8

0.9

1.3

2.0

2.4

3.9

2.7

6.0

9.1

12.1

9.0

2.2

2.4

5.9

0.6

0.8

0.7

1.1

1.1

1.6

0.2

1.9

1.3

0.8

1.6

0.8

1.5

1.3

F

D

F

12,610

14,730

14,350

4.3

2.7

2.4

37.7

17.2

33.0

47.1

76.1

60.0

10.9

4.0

4.6

4.3

2.7

2.4

68.9

84.7

80.8

5.4

4.3

5.1

0.5

0.6

0.7

8.5

2.2

4.8

WA

WV

WV

WY

WY

G

I

Ultimate Analysis

Carbon (%)

Hydrogen (%)

Nitrogen (%)

12,960

9,420

5.1

23.2

40.5

33.3

49.8

39.7

4.6

3.8

5.1

23.2

73.0

54.6

5.0

3.8

0.5

0.4

10.6

13.2

*Orchard Bed. **Mammoth Bed. ***Holmes Bed.

RANK KEY: A-Meta-anthracite

B-Anthracite

C-Semianthracite

D-Low Volatile Bituminous

E-Medium Volatile Bituminous

F-High Volatile Bituminous A

G-High Volatile Bituminous B

H-High Volatile Bituminous C

1-Subbituminous

Proximate Analysis

J-Lignite

Table 3-4. Typical coal and ash analysis information suitable for boiler design.

CANCELLED

Typical

________

Range

________to________

Typical

________

Range

________to________ Moisture (%)

________to________

________to________

Ash (%)

Fixed Carbon (%)

Total

Btu per pound (as received)

Btu per pound (dry)

Sulfur (%)

________

________

100.0

________

________

________

________

________

100.0

________

________

________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

1.2

1.0

________

________

________

________to________

________to________

________to________

________

________

________

________to________

________to________

________to________

1.5

1.5

1.6

TM 5-810-15

Table 3-4. Typical coal and ash analysis information suitable for boiler design. (Continued)

Typical

As Received (Raw)

Range

Chlorine (%)

Sulfur (%)

Ash (%)

Oxygen (%)

________

________

________

________

________

________to________

________to________

________to________

________to________

________to________ Moisture (%)

Mineral Analysis

Silica, SiO

2

Ferric Oxide, Fe O

3

Alumina, Al O

3

Titania, TiO

2

Calcium Oxide, CaO

Magnesium Oxide, MgO

Sulfur Trioxide, SO

Undetermined

Total

3

________

________

________

________

________

________

________

________

________

________

________

100.0

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

Reducing

Fusion Temperature of Ash, deg. F

Initial Deformation (IT)

Softening (H=W)

Hemispherical (H= 1/2W)

Fluid (FT)

Free Swelling Index

250

Silica Value

Base/Acid Ratio

________

________

________

________

____________

____________

____________

____________

________to________

________to________

________to________

Sulfur Forms

Pyritic Sulfur (%)

Sulfate Sulfur (%)

Organic Sulfur (%)

Water Soluble Alkalis

________

________

________

________to________

________to________

________to________

Water Soluble K 0

2

Equilibrium Moisture

Hardgrove Grindability Index

________

________

________

________

________to________

________to________

________to________

________to________

Typical

________

________

________

________

________

________

________

________

________

________

________

________

________

________

________

________

100.0

Washed

Range

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

Oxidizing

____________

____________

____________

____________

________

________

________

________

________

________

________

________

________

________

________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

________to________

3174.

3-5. Coal ash characteristics.

a. Slagging and fouling potential. The slagging potential of ash is the tendency to form fused deposits on tube surfaces exposed to high temperature radiant heat. The fouling potential is potential. One testing method of determining ash

CANCELLED the tendency of ash to bond to lower temperature convection surfaces. The slagging and the fouling potential of the coal also directly affects furnace fusion temperature is prescribed in ASTM D 1857.

The test consists of observing the gradual thermal deformation (melting) of a pyramid shaped ash sample and recording the Initial Deformation

Temperature (IT), Softening Temperature (ST),

Hemispherical Temperature (HT), and Fluid

Temperature (FT). The stages at which these temperatures are recorded are shown in figure 3-4.

design. Ash analyses of the expected fuel source

(2) Chemical analyses. The fusion must be performed before undertaking the boiler temperature of ash is influenced by the interaction design, using ash prepared according to ASTM D of the acidic oxide constituents silica dioxide

(1) Fusion temperature. Many comparisons of chemical makeup have been developed to analyze the behavior of ash in boilers, empirical testing of ash fusion temperature is still the most basic way of predicting slagging and fouling

2 2 3 dioxide (TiO ) with the basic oxides; ferric oxide

2

(Fe O ), calcium oxide (CaO), magnesium oxide

2 3

(MgO), and potassium oxide (K O)—all of which

2 are present in the coal ash in widely varying

3-7

TM 5-810-15

proportions. Depending on their relative proportions they can combine during combustion to form compounds with melting temperatures ranging from 1610 degrees F for sodium silicate

2

3

3

(CaSiO ). In determining the slagging potential and fouling potential of ash, studying the base/acid ratio, silica/alumina ratio, iron/calcium ratio, iron/dolomite ratio, dolomite percentage, silica percentage, total alkalies, and the role of iron in coal ash can all be useful, as shown in figure 3-5.

The chemical elements found in coal, their oxidized forms, and the ranges in which they may be present in coal ash are listed in table 3-5.

3-8

CANCELLED

Table 3—5. Chemical Constituents of Coal Ash.

b. Ash characteristics and boiler design. The characteristics and quantity of ash produced by a specific coal strongly influence several aspects of pulverized coal, ACFB and stoker boiler design, including the selection of a bottom ash handling system and furnace sizing. Ash with a high (2400 degrees F and above of a reducing basis) fusion temperature is most suitable for dry bottom boilers, while lower (1900 degrees F to 2400 degrees F on a reducing basis) ash fusion temperatures are

TM 5-810-15

required for wet bottom boilers to prevent solidification of the ash during low load operation. Furnace volume must be increased for coals producing ash with high fouling and slagging potentials, or to counteract the erosive effects of large quantities of ash or very abrasive ash. The greater furnace volume results in both lower exit gas temperaturesreducing fouling and slagging-and lower exit gas velocities, reducing tube erosion. The relationship between coal classification and furnace volume is shown in figure 3-6.

3-6. Combustion technology selection.

a. Exclusionary factors. Gas and oil fired boilers are available over the entire size range. Their use is limited to areas where these fuels are economically available. Stoker-fired boilers are available for the entire load range covered by this manual.

Pulverized coal (PC) boilers are available in capacities of 100,000 pph and above. Atmospheric circulating fluidized bed (ACFB) boilers are available in capacities of 80,000 pph and above. PC fired units were used in capacity ranges below 100,000 pph prior to the advent of package boilers, but with the new designs it became more difficult to evaluate

PC firing as a preferred method of firing coal and hence have essentially become obsolete. When

CANCELLED

3-9

3-10

TM 5-810-15

rapid load swings are expected, stoker-fired units may be eliminated because of their inferior response to these conditions. When economics dictate the use of low grade fuels including those of high or variable ash content or high sulfur content then stoker-fired and PC systems may be eliminated in favor of ACFB systems. If none of these firing systems are excluded by these factors, then the choice between firing systems must be made on the basis of a life cycle cost analysis (LCCA).

b. Base capital cost. The base capital cost of a dual firing system is the total price of purchasing and installing the entire system, including the boiler, furnace, either stoker, pulverizer or fluidization system, fans, flues, ducts, and air quality control equipment. PC fired and ACFB boilers are more expensive than stoker-fired boilers of a given capacity, in part because they have a larger furnace to provide space and time for the combustion process to go to completion. Approximately 60 to

90 percent of the ash content of the coal passes through the unit along with the gases of combustion. Tube spacing within the unit has to be provided in order to accommodate this condition and the ability of this ash to cause slagging and fouling of the heating surface. These factors can increase the size of the boiler and its cost. PC fired units have been replaced by packaged boilers in capacity ranges below 100,000 pph. Gas, oil and

PC boilers require a flame failure system which increases their cost. The total cost of an ACFB boiler addition is offset by not requiring flue gas desulfurization (FGD) or selective catalytic reduction (SCR). Selective noncatalytic reduction

(SNCR) is required on ACFB boilers in place of

SCR.

c. Average boiler duty. The remaining expenses calculated for an LCCA are all functions of the average boiler duty. This value is based on the negotiating fuel supply contracts.

e. Fuel selection considerations. The use of natural gas has the lowest first cost provided there is adequate supply in a nearby supplier

*s pipeline.

Natural gas does not require storage facilities; however, it is subject to interruption and possible curtailment. Although diesel oil burns more efficiently than natural gas, oil requires on site storage and pumping facilities. Because oil has the potential to contaminate ground water, storage facilities are required to include spill containment and leak detection systems. Coal can be stored in piles outdoors. Steel tanks and spill containment are not required. Coal pile runoff (coal fines in rain water) into surrounding waters and airborne fugitive dust emissions are concerns that have to be addressed.

Transportation of coal from stockpiles to the bunkers requires dedicated labor to operate unloading, storage, reclaim, and handling systems.

These needs along with sizing, ash handling, and particulate emissions reduction requirements make coal firing the highest capital investment alternative.

f. Solid fuel considerations. Due to the special coal sizing requirements of stoker and ACFB fuel for such a unit may cost (5 to 15 percent) more than the unsized coal that could be purchased for a

PC fired unit. However, if unwashed or run-ofmine (ROM) coal is purchased for a PC fired unit, a crusher and motor should also be included in the coal handling system in order to reduce the coal particle size to approximately 1-1/4 by 0-inch.

Another consideration is that it may be difficult to obtain the size stoker or ACFB coal due to either transportation difficulties or lack of equipment at a mine site. When using the same bituminous quality coal, PC and ACFB fired units have a higher thermal efficiency (86 to 88 percent) compared to stoker fired units (80 to 84 percent) that effectively estimated annual boiler load during the expected life of the plant. It is calculated as follows: average load (pph) rated capacity

X

CANCELLED

For example, if a 100,000 pph boiler operates at an average load of 75,000 pph for 8,000 hours per year out of a possible 8,760 hours, the average lowers their fuel usage costs. The primary reason for these differences is unburned carbon loss and dry gas (exit gas temperature) losses and amount of fly ash reinjection. These efficiency percentages will western fuels having a high moisture content (20 to

30 percent), a PC fired unit efficiency may be as low as 82 to 85 percent. A particular ACFB boiler boiler duty is 68 percent.

d. Fuel flexibility. When economically feasible the ability to satisfy steam requirements with more then one type of fuel offers significant advantages.

Problems with only one fuel

*s source, transportation, handling or firing system will not stop steam production. The flexibility of alternate fuel supplies can be a powerful bargaining tool when can fire a wide range of low grade inexpensive fuels. These include high sulfur coal, petroleum coke, refuse derived fuel, waste water plant treatment sludge and mixtures of coal with various scraps such as shredded tires, wood chips and agricultural waste. Another feature of PC and

ACFB fired units that results in increased costs and must also be considered in the overall evaluation is

TM 5-810-15

the natural gas or No. 2 fuel oil burner lighters which are normally in the range of 3 million to 10 million Btu per hour for each device. Stoker fired units are normally started by spreading kerosene or other waste oil and scrap wood over a coal bed and lighting it. Annual fuel cost is based on the cost of the fuel, in dollars and cents per million Btu multiplied by the hours of operation and average load and divided by the percent boiler efficiency.

g. Power cost. Gas fired boilers have the lowest electrical energy requirements. Oil fired units are next due to oil pumping and heating needs. Auxiliary power requirements for gas and oil boilers are considerably less than coal fired units because ash handling, coal handling, sorbent handling and pollution control systems are not needed. A comparison can be approximated by listing the fan and drives with their respective duties and the sizes of each. For example, on a PC fired unit there are forced draft (FD) and induced draft (ID) fans and drives, primary air (PA) fan(s) and exhauster(s) and drive(s) and pulverizer drive motor(s). It is possible the primary air fan or exhauster drive and pulverizer drive motor may be combined so there is a single motor driving both devices. Normally, there would be two or more pulverizers and PA or exhauster fans per boiler unit. For the stoker fired unit, there are also an FD and ID fan drive, and an overfire air and ash reinjection system that likewise may be combined as a single piece of equipment.

The pulverizer drive and primary air fan and exhauster drive are relatively high duty or horsepower (hp) consumers compared to the stoker vanadium in the oil. ACFB boilers have higher maintenance when compared to PC boilers. The abrasive action of the solids circulating through the combustor and solids separator causes wear. ACFB systems are more complicated with more components which add to the maintenance cost. As more ACFB experience is gained, maintenance costs can be expected to decrease as improvements are made. Maintenance costs for a PC fired unit are generally higher than that for a stoker fired boiler due to the higher duty requirements of such items as the pulverizers, primary air fans or exhausters, electric motors, coal lines and greater number of sootblowers. Maintenance costs are also a reflection of the hours of operation and average boiler duty.

i. Operating costs. These expenses include manpower, sorbent, and other costs incurred on a continuing basis while the plant is in operation.

Manpower requirements for oil fired boilers are somewhat higher than gas boilers, because of the fuel storage and increased handling concerns associated with oil. Coal fired technologies require considerably more manpower than either oil or gas.

Fuel handling, ash handling and pollution control systems account for the majority of the increase in operating costs. Even though stoker fired and PC boilers are less complicated than ACFB boilers, stoker and PC boilers, unlike ACFB boilers, must include scrubbers. The evaluation of operating costs among coal firing technologies is site specific and must include all relevant factors.

3-7. Pulverizers (Mills).

overfire air and ash reinjection system fan drive together with the stoker drive motor. Annual power costs, kilowatthours per year, is directly related to average boiler duty. Sootblower motors are fractional horsepower and generally are not included in any power comparison. ACFB boilers also have high electrical power requirements. The fluidized bed is suspended on air that is provided by a primary air fan. The solids reinjection device has

CANCELLED is unique to ACFB. Inert bed handling is also in this category. ACFB boilers, however, unlike PC and stoker boilers, may not require sulfur removal and ring-and-roll.

(1) The ball and tube type mill is commonly used on boilers that use coal as the principle fuel.

They require more space and use more power input than the other types, so they are at an economic disadvantage unless only one mill is used.

(2) Attrita type mills are usually used on boilers that use gas or oil as the primary fuel with coal as a backup fuel. These mills are subject to equipment such as scrubbers. This must be elements, i.e., ball and tube, attrita, ball-and-race, high maintenance due to the use of unwashed considered when evaluating power cost.

are commonly referred to by the type of grinding

(ROM) coal and foreign objects (rail, spikes, rebar,

h. Maintenance costs. Gas fired boilers have the ers frequently used on industrial sized boilers. They wood) getting into the coal stream. This mill lowest maintenance cost. Oil fired boiler installa-

a. Types. There are four basic types of pulverizcombines the pulverizer and the exhauster in a tions are higher than gas fired systems due to oil single package.

pumping needs, oil storage requirements and boiler

(3) The following information and corrosion and external deposits on heat transfer illustrations primarily pertain to the more frequently surfaces resulting from sulfur, sodium and used ball-and-race and ring-and-roll type mills.

3-11

TM 5-810-15

Figures 3-7 and 3-8 illustrate the two more commonly used pulverizer types.

b. Capacity. Pulverizer capacity is a function of coal type, based on a grindability index, moisture content, and fineness of the product. At least two pulverizers should be provided, and with one pulverizer off line for maintenance the remaining pulverizers should be capable of supplying coal to the boiler at the desired load with worst case coal.

Figures 3-9, 3-10 and 3-11 show the influence of grindability and moisture content of coal on pulverizer operation.

3-8. Coal burner ignitors.

a. Types. Natural gas or No. 2 fuel oil ignitors are required for firing pulverized coal. These ignitors will be capable of preheating the boiler prior to starting the pulverizer and firing coal. The ignitors should be able to carry about 10 percent of maximum continuous rating (MCR) and are also used to stabilize the coal flame when the burner load is less than approximately 40 to 50 percent or other adverse fuel conditions such as high moisture.

The steam load at which the pulverized coal flame has to be stabilized should be investigated in the design stage so that suitable auxiliary fuel provisions can be designed into the plant. If oil ignitors are used, either compressed air or steam atomizers are used. Pressure on mechanical atomization should not be considered due to safety factors.

b. Cost. The cost of these ignitors and the labor required for their installation plus the fuel system required should be included in the LCCA. Ignitors will be lit by high energy spark plug type lighters.

3-9. Burners and NOx control.

a. Burner design. State-of-the-art burner design calls for low excess air operation to improve the boiler thermal efficiency (reduced exit gas temperature and dry gas loss) as well as to reduce NOx emissions. Coal burners will be specifically designed for pulverized coal and compatible with the gas or oil ignitors to be supplied and produced by a qualified manufacturer. Note, in the case of gas, oil and pulverized coal fired units, a flame safety system is also required.

3-12

CANCELLED

TM 5-810-15

b. Flame safety detectors.

(1) Ultra violet type detectors are used on natural gas and some oil fuels, but will not be used on pulverized coal boilers since the flame masks most of the light rays of that type.

(2) Infrared type detectors are used on pulverized coal boilers to detect coal fire.

performance during backup fuel firing, and the performance over the lifetime of the unit.

(1) Harmful effects of NO on the environment include contributions to acid rain, to the destruction of the ozone layer, to global warming, and to smog.

(2) Components of NO include nitric oxide

(3) For reliability, with a suitable life span, solid state type controls should be used for the detectors.

x

CANCELLED x mandated by recent regulations. The nitrogen content of fuels, especially oil and even coal, should be specified in the fuel purchase contract.

Amendments of 1990 (CAAA) requires application the CAAA has more impact in ozone nonattainment areas which are near the nation

*s largest cities.

Restrictions on the nitrogen content will limit fuel x processes. Emissions from combustion processes flexibility. A careful analysis of proposed NO x reduction technologies must be performed to ac-

State implementation plans may place even more count for any required changes to auxiliary equipment and to identify future increases in O&M costs.

Important questions that should be answered and be a part of the evaluation include the performance over the system.

(4) NO is formed as a result of oxidizing when the nitrogen contained in the fuel is oxidized.

3-13

TM 5-810-15

3-14

CANCELLED x in the combustion air at high temperatures. At very x x intermediate hydrocarbons present in the flames with the control of fuel and air. Vertical staging includes overfire air (OFA) ports above the main combustion zone. Horizontal staging use registers oxidize.

(5) NO control techniques can be defined as either combustion modifications or post combustion reduction. The goals of combustion modification include redistribution of air and fuel to slow or other devices to introduce air at different points along the flame. Fuel staging establishes a fuel rich zone above an air lean main combustion zone.

Burner out of service (BOOS) techniques direct fuel to lower burner levels, while operating upper burners with air only. Flue gas recirculation (FGR)

2 x and reduction of the amount of fuel burned at peak flame temperatures.

TM 5-810-15

(LNB), OFA, and BOOS other combustion modification techniques include fuel biasing, low excess air (LEA), and fuel reburning. Oil fired boilers have successfully used advanced oil atomizers to reduce x is a technique to reduce NO on smaller industrial boilers.

(7) NO reduction side effects should be potential increases because highly corrosive hydroreducing atmosphere. Changes in flame length can cause impingement and can alter heat absorption characteristics. Fly ash loading may increase at the air heater or particulate collection equipment.

(8) Selective catalytic reduction (SCR) uses considered in the evaluation of alternatives. Reduction techniques may require constant operator attention or a high degree of automation. LNB

*s on coal fired boilers increase carbon loss in the ash by

0.5 to 10% which may require the installation of elemental nitrogen. SCR offers 90 percent or

1600 degrees F and 2200 degrees F. Catalyst is

Catalyst life is guaranteed up to 5 years and has classifiers and reinjection lines. Loss on ignition

(LOI) reduction techniques have other impacts.

Classifiers may place constraints on pulverizers reportedly been as long as 10 years. Catalyst replacement is the largest part of O&M costs. The other popular form of post combustion technology which decrease operation flexibility. Unit efficiency may decrease if excess air has to be increased.

Changes in slagging patterns may occur. Soot blowing may be needed more frequently.

Difficulties may arise during changes in load.

Mechanical reliability may decrease. Burner barrel temperature is difficult to control with some LNB

*s which leads to premature failure. Corrosion is selective noncatalytic reduction (SNCR). SNCR involves the injection of either urea, ammonium hydroxide, anhydrous ammonia, or aqueous ammonia into the furnace within the appropriate temperature window (1600 degrees F to 2000 house” gas. Ammonia emissions of “slip” is an-

3-15

TM 5-810-15

3-16

involves modifications to pressure parts. Fuel staging requires pressure part modifications for reburn fuel injection and/or OFA ports.

other concern. SCR concerns include fouling or blinding catalyst surfaces and poisoning the catalyst with arsenic, lead, phosphorus or other trace compounds found in coal.

3-10.

Primary air.

(9) Operation and maintenance cost increases should be identified. Coal boiler bottom ash systems may have to be retrofitted with ash separators and carbon recovery devices if LOI

CANCELLED hazardous waste. As regulations become more strict additional catalyst could be needed to meet

a. Air moving system. Pulverized coal firing requires heated primary air to dry the surface moisture in the coal fed to the pulverizers and to provide the conveying medium for getting the finely ground pulverized coal from the pulverizer to the burner and out into the furnace. This primary air is supplied either by the FD fan for a hot primary air system or a separate cold primary air fan for x could have detrimental effects on existing NO x reduction equipment.

(10) Installation and retrofit of various NO x reduction systems have unique installation and space requirements that should be considered. LNB may or may not require pressure part modifications.

FGR involves routing large ductwork. OFA is very effective, involves routing of ductwork, and also pressurized pulverizer systems; or is drawn through the pulverizer by an exhauster fan in the negative pressure pulverizer system.

(1) The use of a separate high pressure fan to force the coal through the mill and burner lines to the furnace burner and out into the furnace itself requires all the burner piping, and pulverizer to be sealed against this pressure in order to prevent coal leaks.

TM 5-810-15

(2) In the negative pressure pulverizer operation, the exhauster fan pulls the air through the mill and then forces it up through the riffle box, then the burner lines to the furnace. In this case, any leakage would be into the mill. However, the burner lines are under pressure and any leakage would result in finely ground coal showing up around these leaks.

b. Coal air mixture. In either case, pressure or exhauster type mills, the coal-air mixture is usually at a temperature of approximately 150 degrees F rates over 25,000 pph. It is not recommended because of high costs for installation and maintenance.

c. Acceptable type stokers..

(1)

Vibrating or oscillating grate stoker.

This type of stoker is available for boilers with steam capacities between 20,000 and 150,000 pph, depending upon what feed types are used. It is available with either mass feed or spreader feed.

(2) Traveling grate stoker. This type of stoker moves the coal through the boiler furnace on and a velocity 2000 feet per minute (fpm) or higher, to prevent the coal from settling out in the burner lines. If the coal does settle out in these burner lines, fires or explosions in the burner lines or pulverizers may occur.

a continuous belt made of the stoker grate bars.

Combustion air passes through the grate bars to reach the fuel bed. The combustion air pressure drop across the grate due to the construction of the grate bars is evenly distributed to the fuel at all loads. This design feature makes the traveling grate

3-11.

Stokers.

a. Type. Mechanical stokers continuously supply coal to their grates in a manner that allows for controlled combustion of the coal. There are several combinations of stokers and grate types hereafter referred to as stoker types and are available for use in coal fired boilers with steam capacities of stoker acceptable for use with spreader type coal feed. For mass burning, plenums and dampers must be incorporated into the design of the stoker. The traveling grate stoker is acceptable for boilers with steam capacities of 50,000 pph and above.

(3) Traveling chain grate stoker. This type of stoker moves the coal through the boiler furnace on a continuous belt made of interlocking links or

20,000 to 250,000 pph which is the entire range covered by this manual. However, not all of them are acceptable for state-of-the-art boiler plant design.

b. Unacceptable stoker types.

(1) Dump grate stoker. This type of stoker is not recommended because it has a high particulate emission rate whenever the grates are dumped. This factor necessitates added cost for air bars. Unlike the traveling grate stoker, it has a low pressure drop across the chain due to the spaces between the links. As a result, the air flow on this type of stoker is not evenly distributed at all boiler loads. Therefore, the traveling chain grate stoker is acceptable only with a mass type feed in boilers with steam capacities between 20,000 and 75,000 pph.

pollution control equipment due to the increased size required to handle the dust loading.

Maintenance costs are relatively high. However, one use of this type of stoker that may be desirable is in conjunction with a pulverized coal fired unit

3-12.

Stoker feed.

a. Types. Two types of stoker feed are available for use with vibrating grate and traveling grate stokers; cross-feed (or mass feed) and spreader for the reduction of refuse derived fuel (RDF) at feed distributor (or flipper). Selection of one type the furnace hopper outlet. The use of this type of stoker in the described application will prevent large particles of refuse that fall to the bottom of the furnace from being dumped into the furnace ash pit before having been completely consumed in the or other of these stokers will depend primarily on a comparative analysis of the capital and operating costs associated with the pollution control equiping chain grate, only a mass fuel feed type will be combustion process.

(2) Single retort underfeed stoker. This type of stoker is not recommended to be used in boilers with steam capacities above 25,000 pph which is at the low end of the size range addressed by this manual. Because of its limited application, the single retort underfeed stoker will not be considered for this manual.

(3) Multiple retort underfeed stoker. This type of stoker is a grouping of the single retort underfeed stokers to increase potential applications of the underfeed retorts for boilers with steaming used.

b. Cross feed. This type of stoker feed is a mass fuel overfeed in which coal is placed directly on the grates from a coal hopper. Continuous feed is automatic as a fuel bed moves away from the coal hopper. This type of fuel feed must have adjustable air dampers under the fuel bed to control combustion zones. The depth of the fuel bed is generally controlled by a gate.

c. Spreader feed. This type of stoker feed throws coal to the rear of the furnace and evenly distributes coal from side to side with a small degree of

3-17

TM 5-810-15

segregation. Approximately 25 to 50 percent of the coal is burned in suspension by this method. This spreader feed has a larger grate heat release rate than the cross feed type; requires a smaller furnace envelope; and has a quicker response time for load changes. This type of fuel feed must have a uniform air flow through the grates due to the large amount of suspension burning. For best results, the fuel fed to this type of unit should be properly sized. Refer to Figure 3-12 illustrating coal size.

d. Stoker selection considerations. Table 3-6 provides a summary of factors to be considered when selecting a stoker for a boiler within the range of 20,000 to 250,000 pph of steam. Prior to submitting a set of specifications to the boiler or stoker manufacturers, the type of coal that is to be burned must be known. Selection of the design coal is required so that these manufacturers are able to guarantee their equipment performance. When the coal is not known, or when the possibility exists that many different types of coals will be burned over the life of the stoker, the selection emphasis should lean toward spreader stokers. This type of stoker is more flexible in its capability to efficiently burn a wider range of coals.

3-13.

Fly ash reinjection for coal firing.

a. General. A fly ash reinjection system for coal fired boilers is used to return coarse, carbon bearing particulate back into the furnace for further combustion. This is only economically justified in stoker fired boilers with steam capacities over

70,000 pph. Fly ash reinjection from the boiler, economizer, air heater and dust collector hoppers can improve boiler thermal efficiency by 3 to 5 percent. However, fly ash recirculation within the boiler is significantly increased.

b. Equipment sizing. Tube erosion and other maintenance costs in addition to requiring an increase in the capability of the air pollution control equipment are to be expected and must be taken into consideration when sizing the air pollution control equipment.

3-18

CANCELLED

TM 5-810-15

Table 3-6. Stoker Selection Factors.

Applicable

Boiler Size, pph

Maximum Grate

Heat Release,

Maximum Furnace

Heat Release,

Coal Parameters

Moisture %

Volatile

Matter %

Fixed Carbon %

Ash %

Btu/lb (Mm)

Free Swelling

Index (Max)

Ash Softening

Temp, F (Reducing

Stimulus)

Coal Size

Max Fines thru

1/4” Screen Max

Stoker Turndown

1

(Stable Fire)

Particulate

Emissions

Crossfeed

100,000-

150,000

400,000

Vibrating

Grate Stoker

Spreader

Feed

20,000-

150,000

600,000

25,000

0-10

30-40

40-50

5-10

12,500

2,300

1”x0”

40%

3:1

1.0-1.5

25,000

0-10

30-40

40-50

5-10

2,300

1-1/4"x3/4”

50%

3:1

1.4-10

Crossfeed

100,000-

250,000

450,000

Traveling

Grate Stoker

Spreader

Feed

50,000-

250,000

750,000

25,000

2-15

30-45

40-55

6

11,000

2,200

1”x0”

60%

3:1

0.6-1.5

25,000

0-10

30-40

40-50

5-15

2,300

1-1/4"x3/4”

40%

3:1

1.4-10

Traveling

Chain Grate

Stoker

Crossfeed

20,000-

75,000

450,000

25,000

2-15

30-45

40-55

6

11,000

5

1,900

1”x0”

60%

3:1

0.6-1.5

1

To achieve this turndown rate, reference should be considered in the construction of the boiler for either membrane or welded wall construction or tube and tile type construction. Note some loss in boiler thermal efficiency will occur at lower loads.

Note: Coal sizing and quality have a direct influence on the efficiency of stoker fire boilers. These selection factors do not apply to those western fuels which have high moisture 25 percent or more content and have a lignite type ash characteristic.

3-14.

Overfire air.

a. General. Overfire air is the ambient air supplied by either the FD fan or a separate fan that may also be used for fly ash reinjection and is used air which controls the velocity of solids through the

CANCELLED on all types of stoker fired boilers. The purpose is to aid combustion and to insure the coal particles are as completely burned as possible.

combustor. Ash must be removed from the bottom of the combustor to control solids inventory, bed quality, and prevent agglomeration of solids.

Arrangement of tuyeres or air distribution devices must direct ash flow toward bed drains. Figure 3-

13 shows the major ACFB boiler components.

b. Upper combustor and transition zone. The

b. Port location. Overfire air ports are located on upper combustor is waterwall design. Solids and either or both the front and rear furnace walls.

gases leave the combustor through a transition section which must account for three dimensional

3-15.

Atmospheric circulating fluidized bed

thermal expansion between the major boiler components.

c. Solids separator. The transition section with

(ACFB) boiler components.

a. Lower combustor. Fuel is fed into the refractory lined lower combustor section where fluidizing air nozzles on the floor of the combustor introduce expansion joint connects the combustor to a solids separator. Two different separator designs include

3-19

TM 5-810-15

3-20

mechanical cyclone type and U beam. Cyclone separators are more common. Cyclones can be either water or steam cooled to reduce refractory thickness.

d. Solids reinjection device. Solids that have been removed in the separator are reintroduced into the combustor for additional carbon burnout and increased combustion efficiency. This recirculating loop is sometimes referred to as the “thermal fly wheel.” Solids reinjection devices consist of a refractory lined pipe with fluidizing air nozzles.

This device is frequently called either a J-valve, Lvalve or loop seal. Sorbent for sulfur capture enters the boiler either through the reinjection device or temperature of no more than 700 degrees F, boiler manufacturers will normally use a single section style superheater. Superheaters on coal fired units are of the pendant type and hence are not drainable.

Further, superheaters are either exposed to the radiation of the fire in the furnace, or are located above a "nose" usually on the rear furnace wall that provides for a radiant-convection superheater surface. The design and construction of superheaters is in accordance with the ASME

Boiler and Pressure Vessel Code that applies to the boiler. Normally, superheaters for boilers covered by this manual, will have tubes made of carbon steel, either SA-210 or SA-192, whereas the through separate feeders into the lower combustor saturated or water carrying tubes of the boiler and section.

e. External heat exchanger (EHE). One design includes the use of an EHE to recover heat from recycled solids. Most manufacturers do not use an furnace will be made of carbon steel type SA-178.

(1) For proper operation, particularly of pendant, nondrainable type superheaters, fluid pressure

CANCELLED

EHE due to problems encountered.

3-16.

Boiler components.

steam through the tubes. It is desirable to locate the steam outlet connection at the center of the superheater outlet header for proper steam distribution, but end outlets are acceptable if proper

a. Superheaters. Superheaters receive saturated design consideration is given to the flow steam from the boiler steam drum after having gone distribution imbalances caused by the header conthrough the steam and water separating figuration.

components within the steam drum. This steam

(2) A factor to be considered about supershould have a purity of 1 part per million (ppm) or heater pressure drop is the power cost required for better depending on the quality of the boiler water.

the boiler feed pump. The higher the pressure drop,

The superheater is sized so as to add sufficient heat the more pump power required.

to the steam to obtain the desired final steam temperature. For units with a final steam

firing lignite or subbituminous coal or any coal that has an inherent moisture content greater than 15 percent. Air heaters are normally not used on stoker fired boilers where the coal being burned has a caking tendency. Coal of the caking type is normally associated with areas such as the midwest.

Air heaters are required on pulverized coal and

ACFB fired boilers to heat the combustion air and the primary air. The use of either a recuperative or regenerative type air heater may be determined by space requirements, desired exit gas temperature, maintenance and related costs and other factors involved in a LCCA. The air heater reclaims some of the heat energy in the escaping flue gas and adds that heat to the air required for the combustion of the fuel. This not only decreases the heat loss to the stack, but also decreases the excess air required at the burner. Each 100 degrees F increase in air temperature represents an increase of about 2 percent in boiler unit efficiency.

TM 5-810-15

(3) Another factor to be considered in superheater design is the flue gas velocity over the outside of these tubes. This flue gas velocity should normally be in the range of 55 to 60 feet per second

(fps) in order to avoid external tube erosion from the fly ash particles entrained in this gas.

(4) Another factor to be considered for units with superheaters is the outlet steam piping and the shutoff valves. As the temperature approaches 700 degrees F at the superheater outlet, the steam piping material can be either SA-106B or 106C.

This material has an allowable limit of 800 degrees

F and a maximum allowable stress of 10,800 and

12,000 pounds per square inch (psi), respectively.

The higher the steam temperature, the better and more expensive the steam piping material should be.

b. Air heater. Either recuperative (tubular) or regenerative (rotating plate type) air heaters may be used to heat combustion air on stoker fired boilers

Example:

Air Heater example*

Input—MB/hr

140

Effcy.

Increase x Percent x 0.10

Load

Factor x Hours/year x 7,000

Fuel Cost

Dollars x Per MB x 2.00

Fuel Cost

Savings

Per Year

= $196,000

*Example assumes 100,000 lb/hr capacity, 140 MB/hr full load input, 10 percent efficiency increase with air heater, fuel cost

$2.00/MB, and MB = Million Btu

*s. Refer to figure 3-14 for fuel savings that can be realized by preheating combustion air.

Regenerative type air heaters are suitable for a lower exit gas temperature dependent upon the dewpoint of the fuel to be burned.

However, they are more susceptible to pluggage and the probability of requiring water washing should be built into the design of the unit. On the other hand, tubular heaters are also difficult to keep clean and in order to prevent excessive maintenance costs, retubing or manual cleaning, usually an exit gas temperature in the order of 300 to 350 degrees F is preferred.

c. Steam coil air preheaters. Steam coil air preheaters are used to heat air entering the air heater, recuperative or regenerative type, in order to raise the average cold end temperature to prevent acid

(1) The source of the steam is normally low pressure, 100 psig or less, and it is frequently the exhaust steam from some other piece of equipment such as a steam turbine drive or other process that dewpoint corrosion. This type of equipment is normally incorporated into the design of a boiler exhausts steam at a pressure of 15 psig or higher.

(2) When justified by a LCCA, the steam unit for low load operation and startup operation particularly in those areas with low ambient air temperatures. They are desirable in that the main air heaters, recuperative or regenerative, have corrosion sections that are more readily maintained.

coil preheater drains may be individually piped to another receiver tank from which the condensate can be recovered. Drains to this receiver tank may receiver tank is not justified by the LCCA, the air

This type of air heater uses extended surface, preheater drains will be piped to wastewater drains.

normally referred to as fins, to reduce the overall size of this air preheater. The air pressure drop through the steam coil air preheater is generally limited to about 1 inch of water. It is generally located in the duct between the FD fan and the main air heater. However, in those areas that have extremely low ambient air temperatures, it is not uncommon to have an air preheater ahead of the

FD fan that could preheat cold winter air up to about 40 degrees F.

The piping arrangement should conform to the steam coil manufacturer

*s recommendations.

However, it should be noted that this is treated water and the cost for treating should be included in the cost analysis.

d. Economizers. Only bare tube economizers should be used on any coal fired boiler. Finned tube

(extended surface) economizers should not be used on coal fired boilers as they are more susceptible to both pluggage and corrosion when used in

3-21

TM 5-810-15

3-22

conjunction with coal fired boilers. Another desirable feature of the bare tube economizer is that the tubes should be “in line” so as to have clear spaces between each tube. This arrangement enables the

(2) In order to provide the required primary air temperature, economizers may not be used on some pulverized coal fired units. They are generally used on all gas, oil, and stoker fired boilers and as sootblowers to keep the gas lines clear. Extended indicated in b above, and may be the only type of surface economizers for gas and/or oil fired units offer economic advantages when compared to bare tube economizers. Extended surface economizers are lower first cost and have smaller installation heat recovery used on some stoker fired boilers and the only type used on gas/oil fired boilers.

Economizer sections on ACFB boilers are

CANCELLED space requirements. For oil fired boilers fin spacing should take into account the particular grade of oil to avoid fouling problems.

are an integral part of the boiler and are typically not furnished and manufactured by an economizer company. As a rule of thumb, with the common

(1) The purpose of the economizer is to fuels (coal, oil, gas) steam generator efficiency raise the temperature of the boiler feedwater while lowering the flue gas temperature. Economizer surface is usually less expensive than heating surface in either the furnace area or the boiler convection tube bank.

increases about 2.5 percent for each 100 degrees F drop in exit gas temperatures. By putting flue gas to work, air heaters and economizers can improve boiler unit efficiency by 6 to 10 percent and thereby improve fuel economy.

TM 5-810-15

Example:

Input-MB/hr Effcy.

Increase x Percent x 0.06

Load

Factor x Hours/year x 7,000

Fuel Cost

Dollars x Per MB x 2.00

Fuel Cost

Savings

= Per Year

= $117,600 Economizer example*

140

*Example assumes 100,000 lb/hr capacity, 140 MB/hr full load input, 6 percent efficiency increase with economizer, fuel cost

$2.00/MB, and MB = Million Btu

*s.

Refer to figure 3-15 for fuel savings based on reduction of exit or flue gas temperature. Normally an economizer is less costly and requires less space than an air heater.

e. Sootblowers. Sootblowers are used on all heavy oil and coal fired boilers to clean ash deposits from furnace, boiler and superheater surfaces in addition to economizers and air heaters.

Sootblowers will be spaced as specified by the boiler manufacturer to maintain unit efficiency and prevent coal ash pluggage. Ash deposits on the tubes may bridge the space between tubes unless stopped before such pluggage occurs. Sootblowers are used to keep the tubes clean in order to maintain tube cleanliness and hence efficiency.

(1) Sootblowers may be either steam or air blowing.

(2) Unless water scarcity is an overriding factor, only steam should be used due to capital and operating costs of an air compressor and its related system. The cost of water treatment for the steam consumption by the sootblowers is an evaluation factor.

f. Boiler casing or setting. The boiler casing or setting is the most visible component of the unit and if not properly designed may be the source of excessive maintenance costs and loss of boiler efficiency.

(1) The term boiler setting was originally applied to the brick walls enclosing the furnace and heating surfaces of the boiler. Since the boiler settings and casing have been the source of a large portion of boiler related maintenance and operating

(heat loss) costs, a great deal of attention and improvements have taken place. This is particularly true of the recent past during which time boilers became so large that heat losses and maintenance costs would have been totally unacceptable. As the technology of water treatment plus boiler design and manufacturing improved, water cooled furnace

CANCELLED

3-23

3-24

TM 5-810-15

surface replaced the refractory setting. Casing, frequently 10 gage, was used to seal the refractory placed adjacent to the furnace tubes and backed with block type insulation. This construction is still in use on some small boilers applicable to this manual. However; the products of combustion, particularly with coal fired boilers, will cause corrosion to take place and air leaks will develop when the corrosive (mainly sulfur) substances come in contact with the relatively cool casing. The first signs of leakage will be the gases condensing and dripping through the casing. This condition led the manufacturers to place the casing behind the refractory and then insulating over the casing and protecting the insulation with galvanized or aluminum lagging. However, the latest and to date best design is the use of welded wall construction.

Welded-wall construction positively contains internal flue gas pressure by seal welding metal plates between the tubes. Insulating materials cover the outside of the welded-wall tubes. Lagging is then placed over the insulation.

(2) The advantage of the welded wall construction currently being used by all major boiler manufacturers is that it virtually eliminates the flue gas corrosion that has taken place on the boiler casing. Another advantage is that it reduces air infiltration which in turn reduces exit gas temperature and fuel costs as well as the maintenance costs that were involved in repair of the refractory and insulation that previously existed.

The design of boiler settings will include several considerations. High temperature air and corrosive gases will be safely contained. Air leakage will be therefore has less impact energy. Directional or straightening vanes should be used at bends in ductwork to minimize turbulence or draft loss.

h. Desuperheaters. Normally on boilers with an outlet superheat temperature of no more than 750 degrees F, desuperheaters will not be used. However, if the steam is used for a process at a lower pressure and the temperature may be harmful or unwanted, a desuperheater can be installed in the steam line to control the desired temperature. Water for this device will normally be obtained from the boiler feed pump or a separate pump. The source of the water used by the desuperheater will be such as deaerating heater and will be of the same quality as used in the boiler. If a desuperheater is used and the discharge of the device is into the superheater, the water and entrained impurities will be sprayed into the superheater tubes.

i.

Fan blades and applications. Table 3-7 provides a summary of available fan blade types and their respective applications. Individual fan types are more fully described in paragraph 7-12 of this manual. Items that must be identified for the design of a particular fan application include: anticipated flow of air or combustion gas (pph), temperature of air or gas (degrees F), density of air or gas (pounds per cubic foot, lb/ft ), fan inlet pressure (inches water gauge, in. wg), fan outlet pressure (in. wg), and fan curves of applicable fan types.

Table 3-7. Fan Blades and Applications.

Fan Blade Type Application

Backware Inclined Hot Primary Air (HPA) held to a minimum. Heat loss is reduced to an acceptable level. Differential expansion of the com-

Backward Curved

Hollow Air Foil

Cold Primary Air (CPA)

FD, ID, CPA, OFA, BF

FD, OFA, ID, BF ponent parts will be provided. The surface temperature should be such that it would not be a source

Radial HPA, OFA, ID, FTB of hazard or discomfort to operating personnel. If

Open Radial Pulverizer Exhauster located outdoors, should be weatherproofed. The probability of injury or plant damage in the event of an explosion will be reduced. The use of welded wall construction and its inherent strength is design of boiler settings.

g. Flue and ducts. Flues and ducts will be designed to operate at the pressure and tempera-

Radial Tip

FD - Forced Draft.

ID - Induced Draft.

HPA - Hot Primary Air.

CPA - Cold Primary Air.

CPA, ID

CANCELLED

OFA - Overfire Air.

BF - Booster Fan.

FTB - Fly Ash Transport.

ture to which they are subjected. As a general rule, the following velocities will be used in arriving at the cross-sectional flow area of boiler flues and ducts. Cold air ducts—2000 to 2500 fpm. Hot air ducts—3000 to 3500 fpm. Gas flues upstream of particulate collection equipment—2,500 to 3,000.

Gas flues—3500 to 4000 fpm. It should be noted that velocities can be higher at elevated temperatures because the air or gas is less dense and

j. Fan inlet. The following guidelines apply to the fan inlet design.

(1) Intake areas will be at least 20 percent greater than the fan wheel discharge areas.

(2) Fans positioned next to each other will be separated by at least six fan diameters and a separation baffle.

TM 5-810-15

(4) Boilers should not be operated at capacities or pressure and temperature conditions not anticipated by the manufacturer.

(3) Fans will have turning vanes or inlet boxes, or four to five diameters of straight duct at the inlet. The FD, PA, or Overfire Air (OFA) fan inlets located too close to building walls will have splitters.

(4) Where the duct arrangement imparts a swirl to the inlet of the air or gas, the swirl will be in the same direction as the fan rotation.

(5) All fans will use inlet bells to insure a smooth air or gas flow at the fan inlet.

k. Fan outlet. For a minimum pressure drop, there will be three to six diameters of straight duct at the fan outlet.

(5) As previously stated, boilers with superheaters are guaranteed to meet a 1 ppm steam purity condition leaving the steam drum. Boilers without superheaters can be guaranteed to meet a

3 ppm steam purity limit; or in the case of some low pressure, 150 psig saturated and lower, boilers used for heating or similar conditions may only be required to meet a 0.5 percent moisture condition.

These limits are not. stringent if the proper feedwater treatment is used and the proper equipment incorporated in the plant design. In addition, the

3-17.

Boiler water circulation and chemical

operators must make proper use of the boiler water

treatment.

a. Water circulation. A description of the internal or water/steam-circulation features of watertube boilers is listed below:

(1) The limits of the capability of a boiler is determined by water circulation and the feedwater and boiler water treatment. Boilers that do not circulate properly will rupture tubes in a very short period of time when operated at or near rated load.

Such items as superheat and tube metal temperatures as well as fire side design considerations, physical limits of firing equipment and air and gas fan and their physical limits are not being overlooked.

(2) The basic design of boilers and the size pressure and temperature range of this manual are at the lower end of the technology scale.

(3) The American Boilers Manufacturers

Association has set certain standards for boiler water limits. Table 3-8 shows the allowable concentrations for boiler water. These conditions are normally stated in proposals submitted by those manufacturers. They should be considered minimums for feedwater and boiler water treatment. All reputable feedwater treatment blowdown and the addition of the chemical treatment. Steam drum internals are revised when lower guarantee limits are stated. In fact at times, manufacturers may rely on natural separation of steam and water within the steam drum. In this case they may eliminate all steam drum internals except a dry pipe or other such collecting device.

(6) In referring to the proper feedwater treatment and operation of the boiler blowdown and chemical treatment, attention to these items will pay off in the long run in reduced maintenance, retention of design efficiency and minimum cost of feedwater treatment chemicals through elimination of tube deposits and steam carryover problems.

(7) Figure 3-16 graphically describes the difference in the specific weights per cubic foot of water and saturated steam at various pressures up to approximately 3200 psig. This chart illustrates their ratio which may be considered a margin of safety. For boilers operating in the range of 150 to

400 psig, depending on the boiler design, location of the tube in the furnace or boiler area, slope, and other similar conditions, the ratio of pounds of

psig

consultants or vendors will be able to meet and improve on the conditions required for the operating conditions of boilers covered by this manual.

CANCELLED

Operating

Pressure

Total

Solids ppm

Total

Alkalinity ppm

Suspended

Solids ppm

water circulated to the pounds of steam entrained and then released from the steam drum is very approximately 30 to 15 to 1. This ratio decreases quite rapidly as the operating pressure rises.

Circulation is assisted by the height of the boiler as well as the burner heat input located at the bottom of the U-tube which acts as a thermal pump.

b. Chemical treatment.

0-300

301-450

451-600

601-750

3500

3000

2500

2000

700

600

500

400

300

250

150

100

(1) Oxygen (O ) is one of the more troublesome components of feedwater. It is readily removed by proper operation of the deaerating heater together with a minimum water temperature of approximately 220 degrees F leaving that heater.

751-900

901-1000

1500

1250

300

250

60

40

American Boiler Manufacturers Association

Stipulation in Standard Guarantees on Steam Purity

2 sulfite or hydrazine is used in the boiler feedwater

3-25

TM 5-810-15

to make sure any residual dissolved 02 is not permitted to pit the tubes.

cates the steam drum internals showing the chemical feed line and the continuous blow pipe in

(2) Water hardness, expressed as calcium addition to the feedwater line. The diameter and length of the drum are determined by the capacity

3 zero as possible under all conditions. This can be accomplished by proper feedwater treatment and boiler water testing.

(3) Another item of importance is to maintain the proper acidity or alkalinity (pH value) of the boiler in the number of primary or cyclone separators needed. These devices in addition to separating steam and water, aid water circulation by a reactive (pumping) action that promotes water flow along the length of the steam drum.

reading of the boiler water. For boilers in the range of this manual, a pH reading of 9.0 to 10.5 should be acceptable depending on the chemical composition of the water source and the type of treatment used. In the latter category, some of the

(1) The drying screen or secondary scrubbers further separates the steam and water particles so that the steam leaving the drum meets of the steam drum is the reserve water holding more common types of treatment are: sodium zeolite, hot lime zeolite, phosphate hydroxide and coordinated phosphate. In some cases the use of a demineralizer or evaporation may be desirable.

These latter methods are more appropriate for higher pressures and temperatures in a steam cycle that has more complex problems due to the source of water for the boiler or boilers. These water treatment methods are addressed in more detail in chapter 7.

capacity which permits load swings besides being the collecting and distribution point of the steam.

(2) The primary function of the lower (mud) drum is to complete the circuit for the tubes in the boiler section and generally to act as a water reservoir and supply source for the lower furnace wall headers and tubes connected thereto. Except in unusual cases, the lower drum has no internals.

It should be sized so that maintenance people can roll tubes into the drum holes as well as inspect

c. Boiler internals. Figures 3-17 and 3-18 indithose tubes. Some designs may permit rolling of

3-26

TM 5-810-15

the tubes through inspection or handhole access engineering staff. In addition to the various mathports.

(3) The amount of heating surface in the furnace and its configuration is generally arranged to suit the firing method, and to provide the necessary time and space for complete combustion of the fuel. Firing methods include gas, oil, pulverematical approaches for sizing these components a good deal of this design is based on years of experience with its empirical data as well as various manufacturing considerations.

3-18.

Boiler stacks.

ized coal, stoker fired, and atmospheric circulating fluidized bed. The particular fuel(s) fired also impacts design. The boiler bank is sized in conjunction with the furnace and superheater to provide the steam capacity as well as to lower the exit gas temperature to the value required. The economizer, if provided, is sized to lower the exit

CANCELLED operating conditions. Generally this means the economizer is sized to permit a 25 to 50 degrees F margin between the exit water temperature and loads, start-up and shutdown, plus normal weather conditions. Drainage of water should be provided due to operating conditions as well as rain and snow. Some of the factors to consider in stack design are:

(1) Flue gas conditions. The erosive and corrosive constituents, dew point temperature, and maximum temperature if bypassing the economizer or air preheater.

saturation temperature at operating conditions. The point a considerable amount of the time due to low

(2) Temperature restrictions which relate to air heater, if provided, is sized to provide the stack flue gas temperature will be below the dew the methods of construction and the type of stack desired air temperature to the pulverizers or stoker

a. General. In boiler operation applications, the lining material to be utilized.

as well as to lower the exit gas temperature to the

(3) Stack and lining material must be desired value.

selected to withstand corrosive gases (related to

(4) Fitting the size of each component into sulfur in the fuel).

the most efficient and least expensive unit is the

(4) Wind, earthquake and dead loads, which function of the boiler manufacturer and their includes the moment 1 load from deflection.

3-27

TM 5-810-15

(5) After structural adequacy has been determined, both static and dynamic analyses should be made of the loads.

(6) With welded steel stacks, a steady wind can produce large deflections due to Karmen Vortices phenomenon. If the frequency of these pulsations is near the stacks natural frequency, severe deflections can result due to resonance.

the stack, and friction losses in the stack should be provided by the natural draft of the stack.

Barometric pressures adjusted for altitude and temperature must be considered in determining air pressure. The following stack parameters must be determined:

(1) The extreme and average temperatures of ambient air and gas entering the stack.

(7) The plant location, adjacent structures, (2) All heat losses in the stack (to find mean and terrain will all affect the stack design.

(8) Cleanout doors, ladders, painter trolleys,

EPA flue gas testing ports and platforms, lightning protection and aviation warning lights will be provided, as required.

stack temperature).

(3) Altitude and barometric corrections for specific volume.

infiltration of air and combustion air into the stack

b. Stack design. The stack height calculations are for the effective stack height rather than the actual height, this is the distance from the top of the stack to the centerline of the opening of the stack where the flue gas enters. Air and gas flow losses through the inlet air duct, air heater (air side), windbox, furnace and passes, air heater (gas side) or economizer, gas cleanup equipment and other losses through duct and breeching should be plotted and overcome with the fans. The kinetic casing and ductwork must also be considered.

(5) stack.

(6)

(7)

Stack draft losses due to fluid friction in the stack and kinetic energy of gases leaving the

The most economical stack diameter and the minimum stack height to satisfy dispersion requirements of gas emissions.

The stack height for required draft.

(Where scrubbers are used, the temperature may be too low for sufficient buoyancy to overcome the discharge head, the friction losses at the entrance to stacks internal pressure losses.)

3-28

(8) A static and dynamic structural analyses must be made of the wind, earthquake, dead, and thermal loads. Vortex shedding of wind loads must be considered to be assured that destructive natural frequency harmonics are not built into the stack.

d. Stack construction. The stack height and diameter, support, corrosion resistance, and economic factors dictate the type of construction to be utilized.

(1) Stacks are generally made of concrete or steel because of the high cost of radial brick construction. If stack gases are positively pressurized, or if flue gases will be at or below the dew point of the gases, corrosion resistant linings must be provided; linings must be able to withstand temperature excursions which may be experienced in the flue gas if flue gas scrubbers are bypassed.

(2) Stacks of steel or concrete construction will be insulated to avoid condensation by not allowing

TM 5-810-15

the internal surfaces to drop below 250 degrees F.

This requirement does not apply when scrubbers are used with low temperature discharge (150 to

180 degrees F) into the stack because the flue gas is already below dew point temperature.

(3) A truncated cone at the top of the stack will decrease cold air downdrafts at the periphery of the stack and will thus help maintain stack temperature, but stack draft will decrease considerably.

3-19.

Adjustable Speed Drives.

Significant electrical power savings can be realized at reduced boiler loads by installing adjustable speed drives (ASD) on ID and FD fans. The economics of ASD

*s depend on the boiler load profile (number of hours at different loads). The feasibility of ASD installation should be verified by an LCCA.

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3-29

CHAPTER 4

AIR QUALITY CONTROL AND MONITORING EQUIPMENT

TM 5-810-15

4-1. General.

Refer to TM 5-815-1 for a detailed description of the major air quality control devices available for boiler plant emissions control. Air pollution control guidelines are discussed in AR 42049.

4-2. Particulate control systems.

The types of particulate control systems which are commonly used are mechanical cyclone collectors, fabric filter baghouses and electrostatic precipitators.

4-3. Flue gas desulfurization systems.

The dry and wet types of FGD systems are commonly used to remove sulfur oxides from the boiler flue gas.

The data acquisition system (DAS) stores monitored information, performs necessary calculations and generates the required reports.

c. Gas monitors. Gas monitors can be classified as either in situ or extractive.

(1) In situ analyzers are attached directly to the probe on the stack or breeching. Access for routine maintenance is required and personnel weather protection may also be desirable for outdoor installations depending upon the climate. In situ monitors relay information to the DAS using 4 to 20 mA signals.

(2) Extractive monitors pull samples from the flue gas stream using stack or breeching probes.

The flue gas sample is then transported to the cabinet mounted analyzer located on the plant floor or ground level as required. This cabinet is placed to provide convenient access for operation and maintenance. The interior of the cabinet can also include any necessary heating, air conditioning or humidity control. Extractive systems are further classified as either wet, dry or dilution. Since raw x reduction are selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR). SCR systems require periodic replacement of the catalyst. SNOR removal efficiency is maintained only within a narrow temperature range.

4-5. Air monitoring equipment.

2 of wet samples will cause condensation of sulfuric acid. For longevity of the equipment wet sample tubes must be heated to avoid acid corrosion.

Removal of water from the sample using a cooler

a. General. Federal regulations require new sources to obtain and maintain acid rain permits. A permit is good for five years and must be renewed.

Emission allowances are required to emit sulfur dioxide. Pollutants must be monitored to verify source.

need for heat traced sample lines, pumps, filters or compliance with the acid rain program. Reported values include SO (lb/hr), NO (lb/MB), CO

2

(lb/hr), excess opacity (percent), and heat input

(MB). Measurement options are available to gas/oil fired units, depending upon the type or category of

CANCELLED continuous emissions monitoring (CEMS) are available to certain types and sizes of emitters by petition. A thorough investigation of local, state, concentrations.

d. Flue gas flow monitors. Monitoring of flue gas flow is sometimes required. In these cases flue gas flow is used along with the primary measured value to calculate the reported value. Three types of flue gas flow monitoring systems that have been used include ultrasonic monitors, thermal monitors and differential pressure monitors.

and federal regulations is required for each new dryers. Analyzers are readily available to accurately and reliably measure diluted pollutant

(1)

Ultrasonic flow rate monitors.

Ultrasonic flow monitors consist of two ultrasonic b. CEMS components. CEMS include four major to 200 times. This diluted sample eliminates the transducers mounted at different elevations and on components or subsystems. Gas monitors measure dilute the sample gas in the probe from between 50 opposite sides of the stack. This type of monitor the concentration of pollutants at a particular point

Dilution extractive systems use clean dry air to measures the time required for an ultrasonic pulse in the flue gas stream. Flow monitors measure flue heating. These systems are called dry extractive.

to travel from the downstream transducer to the gas flow and fuel flow monitors measure natural provides a dry sample which no longer requires upstream transducer. The speed of sound in the flue gas and fuel oil flow rate. Opacity monitors indicate gas stream and the flue gas stream temperature are the emission of particulate matter from the stack.

4-1

TM 5-810-15

determined from the average of these two measurements. The velocity of the flue gas stream is determined from the difference between the measurements. An input signal from the plant barometer can be provided so that flow rate can be calculated in standard cubic feet per minute. Automatic zero checks of ultrasonic flow monitors are conducted by sending successive pulses in the same direction. Span checks are conducted by again firing successive pulses in the same direction, but with a time delay between the pulses which represents a specific flue gas flow velocity.

(2) Thermal flow rate monitors. Thermal flow monitors depend on temperature measurements and thermal properties of the flue gas. There are two types of thermal measurement.

One type measures the temperature difference between two similar resistance temperature devices

(RTD), one is heated at a constant rate and the other is unheated. The temperature difference will be a function of the velocity of the flue gas. The higher the velocity, the greater the cooling effect, and hence the smaller the temperature difference.

The other type of thermal probe varies the current to the heated element as necessary to maintain a constant temperature difference. The higher the velocity of the flue gas, the greater the heat rate required to maintain the temperature differential.

Zero and span checks of these devices require their removal from service. Techniques for conducting automatic daily calibration drift tests have not yet been developed.

particulate emissions. A beam of light is projected across the flue gas stream. A measurement detector registers variations in the light transmittance caused by the amount of particulate in the flue gas.

f. Data acquisition systems. Data acquisition systems (DAS) typically consist of personal computers (PC). A typical system includes a central processing unit (CPU), hard disk drive, a floppy disk drive, a keyboard, a cathode ray tube (CRT) or TV screen and a printer. Serial ports and required software are included to accept the input signals from the monitoring equipment. The hard disk drive provides magnetic storage of data and allows quick access for rapid calculation. The floppy disk drive allows storage of years of historical data in more than one remote location which decreases the risk of loosing this information while at the same time provides rapid regeneration of past reports. The printer provides hard copy of all data while the keyboard and CRT allow operator interface. The DAS performs several tasks. Signals from the monitors must be interpreted and stored. This data is stored in the form of ASCII files. A continuous readout of emissions in the required measurement units is produced. The DAS performs monitor calibration errors and bias adjustments. Missing data procedures are also computed and recorded by the

DAS. Required reports are also generated by the

DAS.

g. Regulatory requirements. The regulations include several specific equipment requirements.

(3)

Differential pressure flow monitors.

Differential pressure flow monitors use the pitot tube principle to measure the flow. A pitot tube is a device which measures both the static pressure

These include span values, calibration capabilities, calibration error limits, relative accuracy, bias limits, calibration gas quality and cycle response time.

and the impact pressure created by the flue gas.

The square root of the difference in these two pressures is a function of the gas velocity. Types include single point and across-the-duct averaging.

(1) Proper monitor location for specific installations is essential. The final location must be representative of total emissions, must pass the relative accuracy (RA) test and must meet point/

One version of the averaging pitot probe has a diamond shaped cross-section and multiple impact and static pressure taps along the length of the probe. Standard differential pressure transmitters are used to sense the difference between the static path requirements as outlined in the regulations.

Location has to provide representative flow over all operating conditions. This requires that the velocity velocity over the cross section. Emission rate in and total pressure. These devices are simple and use standard pressure transmitters. In high particulate applications, a purge system may be needed to keep the pitot pressure taps clear. Zero checks are accomplished by pneumatically connecting the two sides of the pressure transmitter. These checks can easily be automated for daily zero drift checks.

Span checks can be performed by using a water manometer. This type of span procedure is more difficult to automate.

e. Opacity monitors. Opacity monitors use the principle of transmissometry to indicate the level of terms of lb/MB must reflect actual emissions.

Monitor location must also represent actual pollutant concentration. Location has to minimize the effects of condensation, fouling and other adverse conditions. Tests are also required to determine the acceptability of the location and to also determine the number and location of flow monitor points.

(2) There are specific reporting requirements that have to be addressed. Notification must be given to governing federal, state and local agencies prior to certification and recertification tests. A

4-2

TM 5-810-15

monitoring plan must be established. Applications have to be submitted for certification and recertification tests. Quarterly reports and opacity reports are also mandatory.

(3) The monitoring plan although not part of the GEMS specifications has several elements that are common to both. Monitoring plans include precertification information, unit specific information, schematic stack diagrams, stack and duct engineering information, monitor locations, monitoring component identification table, DAS table and emissions formula table.

(4) Records have to be maintained for at least three years. Record keeping includes current monitoring plan, quality plan and hourly operating data. Hourly data must include date, hour, unit operating time, integrated hourly gross unit load, operating load range and total heat input in

MMBtu.

(5) The certification tests have to be successfully executed on time. These tests include a 7 day calibration error test for gases and flow, a linearity check, cycle time/response time test, relative accuracy test and bias test. Guidelines clearly outline whether or not recertification tests are required when changes have been made to equipment, location or the DAS.

(6) Quality assurance and quality control procedures must be developed into a well defined program which includes calibration error testing and linearity checking procedures, calibration and linearity adjustments, preventative maintenance auditing procedures or relative accuracy test audit

(RATA). Calibration error tests have to be per-

2 x must be challenged by zero level and high level calibration gases. The measured values must be within 2.5 percent of the cal gas value. If the span is less than 200 ppm then the values must be within percent of span. The measured values have to be within 3 percent of the referenced value. Linearity checks are required quarterly. These checks must use dedicated low, mid and high level cal gases.

Measured values must be within 5 percent of the cal gas value. Average difference among three nonconsecutive checks with each cal gas must be

(7) Several daily adjustments are required.

Error adjustments on gas and flow monitors are required daily. Recalibration must then be performed after each adjustment. A flow monitor interference check is necessary. This includes sample sensing line port pluggage and RTD/transceiver malfunction. An out of control period is when calibration error exceeds two times the calibration error limit or when flow fails interference check.

Data recording must include unadjusted values and magnitude of adjustment.

(8) Quarterly adjustments are also required.

Linearity must be checked on a quarterly basis when no adjustments are made. Leak checks are required for differential pressure monitors. An out of control period is when linearity exceeds limit on any test run or when a flow leak is detected.

(9) Preventive maintenance procedures must be in writing, including equipment manufacturer

*s recommendations. A schedule for the implementation of these procedures has to be maintained. An inventory of spare parts is also required.

(10) A relative accuracy test audit (RATA) is required semi-annually unless accuracy is better than 7.5 percent. The RATA has to be performed during a 7 day period. A minimum of 9 sets of reference method test data are needed. One set of data consists of a 3 point traverse at 0.4, 1.2 and

2.0 meters from the wall of the stack or duct. The gas sample must be analyzed for concentrations or flow using the reference methods. Calculations

2 challenged by zero level and high level calibration gases. For these monitors the measured value must be within 0.5 percent of the cal gas value. Flow monitors are required to zero at 20, 50 and 70 must include determinations of the mean, standard deviation, confidence coefficient and bias. A flow test is required.

CANCELLED

4-3

TM 5-810-15

CHAPTER 5

FUEL AND SORBENT HANDLING AND STORAGE

5-1. General.

This chapter addresses requirements for fuel handling and storage systems for gas, oil and coal fired boiler plants. Solid fuel policies and procedures are discussed in AR 420-49. Criteria for petroleum product storage and distribution is also prescribed in AR 420-49. While not intended to give the reader a complete in-depth study of handling and storage system design, it is written to give a basic understanding of how to select handling and storage system equipment for a small to medium size boiler plant.

site by truck or rail cars. Sorbent is conveyed pneumatically beginning with site storage if required in a silo and plant storage in a limestone bunker. Pneumatic systems are further discussed in this chapter and also in chapter 6. Bunker design should accommodate all possible sorbents being considered. Cylindrical silos and bunkers are commonly used for sorbent storage. Bunker design considerations for sorbent are similar to coal and are discussed in more detail later in this chapter. It is important to measure the amount of limestone going into the combustor. This is done using a belt scale at the outlet of the bunker. The belt scale

5-2. Gas design considerations.

discussion later in this chapter is applicable.

b. Alternate fuels such as petroleum coke can be handled similar to coal. Because of the variance of

a. Natural gas is not stored on site. It is furnished through the supplier

*s pipeline. The takeoff line from the pipe is either furnished by the customer or properties within a single fuel type and especially between fuel types, each system will be designed subsidized by the gas company depending upon how the contract is negotiated. Liquified petroleum for the fuel being considered and the unique site conditions and operating scenarios.

5-5. Coal handling design considerations.

gas (LPG) is stored on site in specially built tanks that can either be leased or purchased.

b. Gas piping will be in accordance with ASME

a. Developing conceptual designs. The process

B31.8, Gas Transmission and Distribution Piping

Systems.

of selecting and laying out coal handling system components should systematically proceed through three preliminary phases before any detailed design

5-3. Oil design considerations.

work is performed: setting design criteria,

a. Fuel oil piping systems require special considevaluating design alternatives, and developing a eration for connections on small pipes. Small flow schematic. The design criteria should address threaded fuel oil piping tends to leak due to the such factors as plant location, climatic conditions, penetrating action of oil under pressure. For this reason it is recommended that pipe 2 inches and smaller be socket welded.

b. Fuel oil storage tank design and installation will include spill containment and leak detection.

Spill containment can be in the form of a double wall tank or a berm as in the case of above ground

CANCELLED system is the leak detection technique of providing underground drainage to a single point next to an above ground storage. A vertical pipe is routed these basic criteria have been established, the designer should present a number of different options that will fit them. The feasibility of each option should be examined, and its advantages and disadvantages should be listed and compared to the other alternatives. Because the lowest capital cost system is not always the most economical system, an LCCA will then be made for each of the different design alternatives, taking into account the from this point to above ground for periodic visual conveying rate and method of coal delivery. After following considerations: Capital investment costs, inspection. A removable cap is used to prevent rain

(stoker or pulverized coal) amount of coal storage, operating costs, and maintenance costs. As a final water from entering the pipe.

available land, system requirements, types of boiler stage of the preliminary design effort, a coal flow

5-4. Sorbent and alternate fuel considerations.

schematic as shown in figure 5-1 will be prepared showing each process and piece of equipment the coal is moved through before reaching the plant storage bunkers.

a. Sorbent or limestone is used for sulfur emissions reduction on atmospheric circulating fluidized bed (ACFB) boilers. Sorbent is transported to the

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5-2

TM 5-810-15

b. Climatic conditions. Annual temperature extremes, rainfall, seismic zone and wind conditions will all affect coal handling equipment selection.

Hostile equipment environments can dictate what type of conveying system is to be selected.

c. Coal conveying rate. The design conveying rate of the coal handling system depends on the maximum daily coal burn rate of the steam plant, including future increases in coal requirements due to plant expansion. Maximum daily coal requirement is computed by using the maximum continuous ratings of all the boilers and conservative values for boiler efficiency and coal heating over the life of the plant. One and one-half shifts per day of running time for a coal handling system at full mobilization would be a reasonable criteria to use.

(1) The conveyor should be operating with the belt fully loaded and at minimum speed for the required amount of material to be handled per hour.

There is no advantage to be gained by running conveyors at high speed while only partly loaded.

(2) The full load on the belt will be considered as approximately 80 percent of the cross sectional load area of the conveyor belt which must take into account that load carrying width is several inches narrower than the actual belt width.

(3) Maximum belt speed for 24, 30 and 36 inch wide conveyors will not exceed 600 fpm and maximum 800 fpm for 42, 48, 54 and 60 inch wide belts and maximum 1,100 fpm for 72-inch wide belts that carry coal. Wider belts should be limited to 600 fpm if possible. Conveyor belts smaller than

24 inches wide will not be used.

d. Coal characteristics and constituents. Designing for a single homogeneous coal type is generally no longer feasible. Where multiple coals will be burned, the conveyer designer must consider the worst case for his or her design based on coal ranking (according to ASTM standards), particle size and shape (sieve analysis), coal density, moisture content, corrosiveness and abrasiveness, sulphur content, angles of repose and surcharge, safe angle of incline, and coal grindability index. Each factor or combination of factors can dictate the type or size of crusher, transfer chute or conveyor that can safely be used to handle the material. The physical and chemical characteristics of coal make it one of the more difficult bulk solids to handle.

Care must be taken by the designer to make sure that he is fully aware of the properties of the coal that is to be handled. A system designed for a values. Once the maximum daily coal burn rate is western subbituminous coal will not be suitable for established, the maximum allowable operating time per day must be defined to arrive at the design conveying rate. It is general industry practice to select the design conveying rate of the coal an eastern coal, and due to the variable constituents, each different type of coal will have a direct influence on air pollution devices, boiler and

CANCELLED handling system so it can transport the maximum daily coal requirements to the steam plant in a single eight hour shift allowing seven hours of design.

e. Conveying western coal.. Because of the increasing use of western, low-sulfur coal in recent actual operation time. This criteria allows coal to years, the designer must take into account that be handled during the daylight hours and provides adequate time for maintaining the equipment in good operating condition. The amount of running time for an Army Ammunition Plant (AAP) should not be confined to the eight-hour per day limitation.

The amount of time that the AAP would be operating at the full mobilization condition has historically been for relatively short periods of time equipment sized to handle a given quantity of eastern coal cannot usually handle the same quantity of western coal, even though the conveyor has been sized to handle the lower density and surcharge angles of western coals. This is partly due to the vastly different range of flow characteristics that are inherent in western coal. A rule of thumb for sizing conveyors for western coal is to go one

TM 5-810-15

belt size larger than recommended i.e. if a conveyor is sized at 30 inches wide to handle a certain capacity, then use a 36-inch wide belt. Conveyor speeds in excess of 700 fpm are not recommended for western type coal.

and 80 ton capacity cars which are more popular at smaller sized plants.

5-7. Railcar unloading system components.

5-6. Coal delivery.

a. General. The method of delivering coal to the plant can be a significant cost in the delivered price of the coal and will affect the design, operation and cost of the coal receiving system. The delivery mode depends on such factors as, plant location, distance from mine to plant, daily “burnrate” under full load conditions, available coal storage area and the cost of competitive transportation methods.

The ability to receive coal by either truck or rail can be advantageous and create a competitive pricing atmosphere. The ability to accommodate 10-15 railcars or higher multiple car shipments can enable the user to obtain lower shipping rates and reduce demurrage on the railcars due to the amount of time a car spends at the plant. Enough track must be provided at the plant site to allow for the loaded and empty railcars and the unloading area. The economic justification for a loop track or spur track rail storage system can be made as a result of savings in freight rates, if space permits.

b. Truck delivery. Trucks are an extremely convenient form of coal transportation, but due to the high manpower and fuel costs, this type of trans-

a. Railcar scales. Railcar scales are optional for large plants if their use can be justified. These scales are usually not installed in a coal handling system.

b. Railcar haulage. The designer can select from capstan type, drum type, or hydraulic type car pullers. Cost is dependent upon the type of car puller arrangement and accessories provided. The capstan type puller is the cheapest, and is used where one or two cars have to be moved. The capstan puller can only be used on level track, and has very limited capabilities. An alternative for very small systems where three to four cars are moved per week, a front end loader fitted with a railcar moving device should be considered. Drum or reversible type railcar pullers provide more versatility and are becoming the most commonly selected units. The operator makes one connection to a “string” of railcars and pulls them backward or forward, up or down grades, and around curves with a car puller. The designer will ensure that the operator and control panel is well protected from the railcar pulling rope. A railcar string is usually one to twelve fully loaded cars. Hydraulic car pullers are usually the most expensive. They are used at larger plants where high volume railcar portation has become expensive. Over-the-road trucks vary in net carrying capacity from 10 to 40 tons. Trucking coal more than 150 to 200 miles to a plant site usually increases the delivered price of coal to a cost that is financially unacceptable for efficient operation. Truck delivery of coal can moving is required. In making a selection, the designer must take number of loaded railcars, track grade, radius of curvature of track (straight preferred), track condition (new or old), operating temperature, and amount of travel distance required into consideration. The designer should usually be incorporated into the design of a railcar unloading hopper. If trucks are the sole method of consult a railcar manufacturer for final equipment selection.

coal delivery, the designer should investigate the c. Railcar shaker. Railcar shakers are used to economics of a covered shed over the unloading hopper. Truck hopper should be a minimum of 12 feet by 12 feet with a steel grating covering the dump area. Maximum grating opening should be 6 inches square. Grating should be designed to vibrate the railcar for fast removal of coal from the railcar without the operator having to get inside the car and manually clear the material out, thus requirements. Car shakers can be the overhead or withstand the loads imposed by the fully loaded truck. Truck weighing scales are optional subject to both economics and justification.

c. Railroad car delivery. This is the most common form of coal delivery to the boiler plant. If a plant has good access to a rail network, the delivery of coal in 70-100 ton railcars is usually more efficient and economical than delivery by trucks. The most common size of railcar is the 100 ton capacity car. The designer should also take into consideration any requirements for the smaller 50 side mounted type. Side mounted car shakers require a foundation outside of the rails, and this becomes a problem if there are two or more railroad tracks spaced close together. This type of shaker is more expensive than the overhead type.

The overhead shaker is the more common of the two types of shaker, having been in proven use for many years. The designer must ensure that suitable electrical interlocks are provided for the hoist and shaker to prevent incorrect use.

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TM 5-810-15

d. Railcar thawing. If the plant is located in a geographical area where the coal would be subject to extreme freezing conditions either from stockpiling the coal, travel time of coal in railcars, or railcars parked on rail sidings for extended periods of time, the designer should make an economic cost comparison to justify whether a railcar thawing system is viable. The car thaw system is used to melt frozen coal from the walls and the bottom of railcars. The thaw system is not intended to completely thaw the entire amount of coal inside the railcar, but rather loosen the bond between the railcar sides and the contents.

(1) Methods. There are two very distinct methods used for railcar thawing. The more expensive method is to spray a chemical freeze conditioning agent onto the coal as it is being loaded into the railcar at the mine site. The other method that is employed is electric or gas infrared radiant energy generation. A combination chemical treatment and thawing system is often used, but this is usually very expensive. Direct flame against the side of the rail cars or the use of explosive charges to dislodge coal inside the railcar, will definitely be avoided. A steam thawing system may be required at an AAP due to the explosive atmosphere, where any naked flame or infrared heating device would be prohibited. Steam thawing is not very efficient and can only be effectively used when large amounts of steam are readily available. This type of system should be avoided where possible.

(2) Design considerations. The car thaw system should be provided with an enclosure or shed around the thawing area. The shed should be at least long enough to accommodate one heating and one soak zone, when using stationary bottom occur.

(1) Sizing. A double hopper arrangement, approximately 28 feet long by 14 feet wide will allow a 100 ton capacity railcar to be placed over the unloading hopper without respotting the car.

(2) Design considerations. The structure will be designed to support the fully loaded railcar and a fully loaded hopper. Bar grating will be provided to protect against personnel and vehicles falling into the hopper. Grating will support the weight of a truck or front end loader. Grate spacing should be a maximum of 6 inches square. The slope angle of all sides of the hoppers will not be less than 65 degrees from horizontal. The angle of the hopper where two sides meet or valley angle will not be less than 60 degrees from horizontal.

Provide capped poke holes at the hopper outlets for use if the hopper becomes plugged.

(3) Materials. A number of track hopper construction options exist and these should be evaluated by the designer for each particular application and the type of coal used. The more common construction materials include three types.

The first is A588 also known as weathering steel with minimum 3/8-inch plate thickness. This type material should not be used for high sulfur coal.

The second type is A-36 mild steel minimum ¾inch plate thickness, with minimum ¾-inch thick type 304 stainless steel bolted or plug welded liners or studs. This type should not be used for high sulfur coal. The third type is solid stainless steel, minimum %-inch plate thickness. The type of material used for hopper construction will be determined by the type of coal being handled. Solid stainless steel hoppers are not usually installed due to the extremely high cost of the material.

dump railcars. The shed length should be increased to handle in motion or unit trains. The car thaw

5-8. Belt conveyors.

heaters are located between the rails and along the

a. Conveyor design. Belt conveyors are used walls of the shed. Reflecting side panels may also be utilized to deflect radiant heat into the railcar.

e. Unloading hoppers. The coal hopper must be sized to accommodate the unloading capacity of

CANCELLED ered by rail or truck. The hopper should have enough capacity to hold at least 100 tons of coal from a stationary positioned railcar, without the most extensively in coal handling systems. They have high handling capacities and offer unlimited possible combinations of length, speed, and capacity. Operating costs and power requirements are low and they are reliable and quiet. Belt conveyors can be designed for practically any desired path of travel limited only by the strength of the belt, conveyor incline or decline, or the space available coal spilling over the tracks. The actual unloading for installation. Troughed belt conveyors normally schedule of the railcars or trucks is very important require more space than other types of conveying and should be timed to prevent overloading a equipment. The designer must make sure that all limited capacity hopper. If railcars are to be conveyor components are suitable for use in a coal unloaded quickly or on the move, the sequencing of dust atmosphere as described by the NFPA and the railcars, the track hopper size, and the size of

NEMA.

the track hopper conveyor must all be coordinated

b. Angle of conveyor incline and belt width.

together so that a choking condition does not

(1) The angle of repose of a material can indicate to the designer how a material reacts while being conveyed on a running conveyor belt. This angle will affect both the capacity and incline limitations of the conveyor. The inclined angle of a belt conveyor should be limited to 15 degrees, with

18 degrees used as an absolute maximum for coal.

High angle conveyors are currently being used by various companies, and the designer should investigate these before a final design is accepted. High angle conveyors use another belt to “sandwich” the material for higher conveying angles. Belt replacement on high angle, flexible sidewall and pocket conveyors is more expensive than conventional belts. High angle type conveyors have more carryback. Conveyor design must consider dirty conditions. Pocket conveyor life is approximately

10 years, while smooth conveyor expected life is 15 years.

(2) The width of the conveyor belt is determined by several factors: the type of material being conveyed, size of lumps, percentage of lumps to fines, the angle of repose of the material and the required belt capacity or conveying rate.

c. Walkways. All conveyors will be provided with a walkway of at least 30 inches in width, including a handrail. Conveyors that are larger than 36 inches wide will also have an additional 18 inch minimum width maintenance walkway on the opposite side.

(1) Walkway construction may be welded bar grating or serrated type expanded metal grating, but wooden walkways will not be used.

TM 5-810-15

The designer will provide adequate access walkways for all conveyors and equipment. Provide adequate width stairways to and from platforms and walkways.

(2) The distance from the conveyor belt line to the top of the conveyor walkway should be between 36 and 42 inches.

d. Weather covers. For open truss conveyors, the belts must be protected from rain and freezing and dust must be prevented from escaping to the atmosphere.

(1) Full or three-quarter cover type, hinged weather covers will be used to protect the belts, yet allow maintenance of the conveyor belt and idlers from the walkway.

(2) The truss will be covered with a continuous deck plate. A typical open truss conveyor is shown in figure 5-2.

(3) For more extreme climates where freezing conditions are a hazard or when airborne dust must be totally eliminated, a totally enclosed type gallery as shown in figure 5-3, should be considered. This type of gallery is far more expensive than the open truss conveyor. Enough room must be allowed around each conveyor in the gallery for maintenance. Tube type galleries are more easily built, insulated and lagged, and washed.

e. Safety escapes. Conveyors will include means of egress that comply with all applicable codes. In no case will the distance from any location on the conveyor to a safety escape to grade level exceed

200 feet.

CANCELLED

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TM 5-810-15

5-6

f. Idlers. Idlers will be selected for a specific condition since they provide the support and protection for the belt and material load and also influence the overall design of the conveyor. Improper idler selection directly affects the belt tensions and thus the final horsepower requirements.

(1) Troughing idlers will have a minimum of three 5-inch diameter equal length interchangeable rolls, with the two outside rolls inclined at 35 degrees from the horizontal.

(2) At least 3 rubber type impact idlers, spaced a maximum of one foot apart or urethane bar loading sections will be placed under each conveyor belt loading point. As an alternative, cradles composed of energy absorbing bars may be used under the loading zone to cushion the impact.

In installations where more than one cradle is ment of at least three percent of the conveyor terminal centers.

(1) Counterweight will be adjustable +/-20 percent from the calculated weight. Counterweight will be designed to limit conveyor belt sag to 2 percent and provide adequate traction for the drive pulley. Loading zone belt sag will be maximum 1 percent.

(2) Screw type takeups are satisfactory for conveyors less than 40 feet in length, but should be avoided if at all possible.

h. Conveyor belt selection. One of the most important design considerations is the selection of the conveyor belt. The belt has to withstand both the initial start up and operating tensions that are encountered within the system, be impact resistant and be suitable for the material being conveyed.

required to cover the length of the loading zone, an (1) The conveyor belt selection must be impact idler will be placed between the cradles to assure proper belt carriage.

(3) Self aligning carrying and return idlers should be placed at 80-foot centers along the length capable of transmitting the maximum belt tension in the conveyor, include the minimum number of belt plies to support the load, pulley series, take into

CANCELLED of the conveyor.

(4) All idlers will have a single point grease lubrication system that is accessible from the minimize belt cost to cover the above items.

(2) Conveyor minimum belt cover thicknesses will be / -inch thick bottom cover

16

(belt side which contacts the idlers and pulleys) and c-inch thick top cover (belt side in contact with walkway side of the conveyor.

(5) Idler construction, selection and spacing will be based upon Conveyor Equipment Manufacthe material).

turers Association (CEMA) standards.

g. Belt take-ups. Belt take-ups are necessary to maintain the proper belt tensions for the drive pulley traction and to maintain correct amount of belt sage between idlers. Gravity type take-ups should be provided on all conveyors with adjust-

(3) The conveyor belt selected must be capable of withstanding all startup and operating tensions that will be encountered within the conveyor. For a multiple ply conveyor belt, the unit tension is expressed in pounds per inch belt width

(piw) or pounds per ply inch (ppi). A 30-inch wide,

TM 5-810-15

3 ply belt with a maximum calculated operating tension of 5000 pounds, will have a unit tension of:

5000 = 167 piw or 56 ppi

30

(4) Conveyor belt sag between carrying idlers should be limited to two percent, except at not use counter-weighted type cleaning devices on conveyors faster than 350 fpm or larger than 36inch as they become ineffective very quickly. V type belt cleaners will be provided on the clean side of the belt before belt take ups and tail pulleys.

load zones limited to 1 percent.

(5) Belt tension will not exceed 70 percent

a. Bucket elevators. These are used to elevate of the Rubber Manufacturers Association (RMA) coal to overhead storage or conveyors, where there tension ratings under normal operating conditions is little available space for a belt conveyor. Malleawith a vulcanized splice.

ble iron, steel, stainless steel, aluminum or plastic

(6) Conveyor belt will be fire and oil buckets can be selected depending on the material resistant conforming to United States Bureau of conveyed. Care should be taken when selecting

Mines Standards.

nonmetallic type buckets for use in a combustible

(7) Consideration should be given in applicaenvironment, due to their ability to retain a static tions of limited takeup or long conveyors to proelectrical charge. Capacity of the bucket elevator vide a mechanical splice when the belt is first will be based upon buckets filled to 75 percent installed so initial stretch can be taken out before theoretical capacity for loading. Drive horsepower doing the vulcanized splice. In these cases run-in will be based upon 100 percent full buckets. There are two common types of elevator used for coal time will be long enough to eliminate manufacturer

*s stretch. Vulcanized belt splices generally last handling: centrifugal and continuous.

close to the life of the belt. Mechanical splices last

(1) Centrifugal type. Centrifugal discharge two to three years.

elevators are the most frequently used type for free

i. Skirtboards. Skirtboards will be provided at all flowing, fine or small lump materials. Buckets conveyor loading points. Coal handling system should be type A or AA as designated by CEMA, design, especially when handling lignite or western spaced at intervals to chain or belt. Buckets are coal requires examination of flow velocity loaded by a combination of material flowing into differences between conveyors, vertical drop at the buckets and material that is scraped up by the transfer points, and angular relationship of condigging action as the buckets pass around the tail veyors. The width of the skirtboards will be maxipulley. Speeds are relatively high and the centrifumum 3/4 belt width.

gal action controls the discharge from the buckets.

(1) Skirtboard length will be at least 2 feet

Capacities range from 5 to 80 tons per hour (tph).

for every 100 fpm of belt speed plus 3 feet at tail

Elevator will be completely self supporting. Cenend. Minimum skirt length will be 8 feet. The skirttrifugal type elevators are used extensively in grain board will terminate above an idler roll, not service and other free flowing materials.

between.

Centrifugal elevators tend to create more dust and

(2) Skirtboard rubber strips with easy adjustcause breaking of friable material, which creates able clamps will be provided on the lower edge of problems with boiler requiring a particular size the skirtboards to prevent the escape of fines.

Wearable liners inside the chute will be installed as a dam to keep the material load off the rubber, so

CANCELLED

j. Belt cleaners. Belt cleaner units on a troughed conveyor belt will consist of a primary scraper on the face of the head pulley and one or more distribution. Centrifugal elevators if used should be vented, and include a filter to relieve the “air pumping” phenomena at discharge.

(2) Continuous type. Continuous bucket elevators are recommended for high capacity heavy duty service. The buckets are steel, continuously space on single or double strand chain or on a belt.

At the head, the discharge from each bucket is over secondary arm and blade type multiple blade the back of the preceding bucket which forms a cleaner to scrape and remove the material that chute to lower the material to the fixed discharge bypasses the primary cleaner. Each belt cleaner will spout. This method of discharge, plus the slow be held in an easily serviceable mounting system

5-9. Other conveying methods.

speed, minimizes breakage of fragile material.

allowing fast and easy blade replacement. The

These types of elevator are not the self digging cleaners will be held in position against the belt by type, so a loading leg must be used, requiring a deeper pit than that needed for a centrifugal discharge elevator. Capacities from 15 to 300 tph means of a tensioner which rotates the blades against the belt yet which allows for relief when mechanical splices or other obstructions pass. Do are available. Elevator will be completely self

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TM 5-810-15

supporting. Bucket elevators are usually high maintenance items and should only be used where space restrictions apply. Manufacturers have to take particular care when designing the track and load shoe.

b. Apron conveyors. Apron and pan conveyors consist of overlapped steel pans which are supported between two strands of chain that pass around head and tail sprockets. This type of conveyor is usually short, slow speed, and used for removing granular or lumpy material from under the track hopper. An apron conveyor is a very high maintenance item and should be avoided when possible. Maximum conveyor incline is usually up inclined and horizontal conveyors. The designer may find it preferable to locate the drive internally or at the tail end of the conveyor if required by accessibility or maintenance, but should be avoided if possible. The drive arrangement should be designed with the minimum amount of compact components as possible. Reducers, couplings and motors should be the same size as far as practical for ease of maintenance and to reduce spare parts inventories. On conveyor drives over 300 hp the designer should investigate the economical justification of dual drives. This type of drive allows the conveyor to be operated at reduced capacity when one of the drive units fails. V belts will not be used.

to 25 degrees or 45 degrees with pusher plates.

b. Reducers. The conveyor drive reducer will be

One distinct advantage of this type of conveyor is

American Gear Manufacturers Association they can carry hot materials.

c. Screw conveyors. Screw conveyors are an ecoinput motor design hp. The thermal hp rating of the nomical short, low tonnage type of conveyor which reducer will not be less than the full load hp of the can be used in areas with low headroom. Screw motor. Bearings will be Anti Friction Bearing conveyors are not usually used when their capaci-

Manufacturers Association (AFBMA) 100,000 ties exceed 50 tph. They are used to handle hour L-10 minimum life. All conveyor drives will pulverized, granular or noncorrosive materials be capable of starting under full loaded conditions.

where product agitation or degradation can be

V belts will not be used.

tolerated. Where mixing or blending is required,

c. Couplings. Power from the reducer drive low numerous conveyor screw configurations are availspeed shaft is transmitted to the conveyor head or able. The conveyor is completely enclosed with drive pulley by the use of a flexible coupling. The only one moving part and can be fitted with coupling will be capable of withstanding parallel, multiple or single discharge openings. Extreme axial and angular misalignment of the drive shafts.

caution must be taken when handling abrasive

The coupling will be incapable of transmitting axial materials, as excessive wear will lead to premature loading and the use of torque limiting couplings equipment failure. As the screw conveyor is will not be permitted. Couplings will be rated using inclined, the carrying capacity decreases. Trough a minimum service factor of 2.0 for the input hp.

loading should not exceed 30 percent of the trough

d. Fluid couplings. Fluid coupling will be procross sectional area for coal, even though higher vided between the drive motor and the reducer loading is possible.

which allows a controlled amount of slip to occur

d. Flight conveyors. Flight conveyors are used to without causing excessive tension and shock loadmove granular, lumpy or pulverized material along ing to the drive components and conveyor belt. A both horizontal and inclined paths. Inclines are fluid coupling will allow the motor to run rapidly limited to approximately 40 degrees, with capacity decreasing as incline increases. One percent of capacity should be deducted for each degree of incline over 30 degrees. Flight conveyor is a high

CANCELLED abrasive materials, the trough design should provide for renewal of the bottom plate without disturbing or removing the side plates or flights. A up to full speed, but will allow the conveyor a smooth controlled acceleration start curve when starting from rest when either empty or fully loaded. This type of coupling is also beneficial in extremely cold climates where a controlled acceleration start is required to prevent coal from backsliding on inclined conveyors. Fluid couplings permethod of compensating for unequal chain wear or

(AGMA) rated using a service factor of 1.5 of the mit the use of standard motors with across-the-line starting capabilities which allows the use of less expensive motors.

stretching must be incorporated into the design.

Flight conveyors are well suited to conveying bottom ash from boilers and sludge from tanks and ponds.

5-11.

Belt scales.

5-10.

Drive units and couplings.

a. Conveyor drive units. The conveyor drive unit should be located at the discharge or head end of

a. Scales. General Belt scales are used to constantly measure the rate at which a bulk material is being delivered to the plant on a moving conveyor belt, and to make a record of the delivered amount

TM 5-810-15

for inventory purposes. It is important to weigh the coal as it is delivered to the plant, and again before it is burned.

b. Type. A belt scale of the weighbridge type which incorporate electronic precision strain gauge load cell and microprocessor based technology with automatic calibration capabilities should be selected. The belt scale, including weighbridge assembly will be capable of withstanding at least 250 percent material overload without damage to any mechanical or electrical components.

c. Scale accuracy. If a belt scale is to be used for basis-of-payment contracts between the coal supplier and the plant, the coal supplier may require a scale with 0.125 or 0.25 percent repeatability accuracy. For general plant inventory purposes, a

0.5 percent accuracy is usually acceptable. If a scale is used for billing purposes or invoicing freight, approval and certification by the weighing bureau which has jurisdiction for that particular geographical area must be obtained.

below 2000 tph and product size is below 3 inches.

Sample system manufacturers will provide help with system sizing and requirements. Due to the complexity and high cost of sampling system, the designer must decide if a sample system is a justifiable piece of equipment to meet the end results.

c. Sweep type sampling. Sweep type (or hammer type) are relatively new and have different design conditions than given above. This type takes less sample than a cross stream type, usually from 1/3 to 1/6 less, depending on conveyor speed, material size and flow rate. This allows two stage sampling systems to be employed with virtually any flow rate using sweep samplers for the first and second stages. Also, for low capacity installations of approximately 50 tph and below, a single sweep sampler with sample collector can be used to meet

ASTM D 2234. At these low flow rates, a manageable amount of sample is collected for laboratory analysis with a minimal capital investment.

5-13.

Magnetic separators and detectors.

d. Readout. The scale can be connected to a computer or a printer to provide a readout of the

a. Magnetic separators. Magnetic separators are quantity of material delivered to the plant. The readout will be easily readable by the operator and be such that he does not have to do any manual calculations to find the amount of coal received.

manually discharged to a collection hopper. A

5-12.

Sampling system.

single unit mounted ahead of the crusher on the

a. General. When a given consignment of coal is conveyor is usually all that is required to protect a delivered to the plant, it may be advantageous to complete conveying system. A small piece of tramp the plant to determine by laboratory analysis some iron can put an expensive crusher out of action of the characteristics of the delivered coal. Samvery easily. The separator will also protect the pling is used to take a representative sample from conveyor belts from being ripped by large pieces of the complete coal consignment lot and provide a tramp iron. A separator is a relatively inexpensive quality evaluation of that sample. Because of the and necessary method for protecting crushing mavariability of the chemical composition of the coal, chinery, conveyors and the plant boilers.

the analytical results from a sampling system can be

b. Detectors. Detectors are used to detect both used to determine coal contract rates, reliable and standards.

efficient quality assurance, plant operating efficiency and compliance with environmental

CANCELLED be designed for a specific location and on an individual plant basis. One sampling system cannot necessarily be used for another similar system.

magnetic and nonmagnetic tramp iron and are usually installed in conjunction with a magnetic separator to provide additional protection for all downstream equipment. When tramp metal is detected, the unit automatically die marks the location and shuts down the conveyor before any damage is done. The operator has to manually remove the foreign material before restarting the

Depending on the capacity of system, one or more conveyor.

sampling stages may be required to obtain the

c. Magnetic pulleys. Magnetic pulleys can also volume of the final sample required for analysis.

be used to remove tramp iron, but are usually not

ASTM standards establish the requirements of the as effective as a magnetic separator, and are seldom final sample for each particular system. A good rule used in coal handling systems.

of thumb for selection is a three stage system is used for flow rates which exceed 2000 tph and by the separator and can be automatically or

5-14.

Coal crushing equipment.

when product size is greater than 3 inches, while a two stage system is used where flow rates are installed to remove potentially damaging magnetic tramp iron from the material on the conveyor belt.

Tramp iron is removed from the conveyed material

a. General. Stoker fired or pulverized coal boiler plants install crushers for use when a larger and

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5-10

TM 5-810-15

more coarse ROM coal has been purchased for use in the boiler plant. A separate crusher bypass chute should be provided to divert coal around the crusher when properly sized coal is purchased and no crushing is required. The separate bypass chute is also advantageous when maintenance work has to be performed, requiring the shutdown or removal of the crusher from the coal handling system.

In boiler plants that have both pulverized coal and stoker fired boilers, all the coal supplied is sized to suit the stokers, with coal going to pulverizers when required. This simplifies the storage and handling facilities required for the system. The crusher will be selected to handle the hardest material that may be encountered in the system. A stationary or vibrating grizzly screen placed ahead of the crusher reduces the crusher size. This can be part of the feed chute to the crusher.

b. Crusher sizing. Generally, crusher drive motor sizing is 1/2 hp per tph for roll crushers, the high speed rotating hammers.

(3) Granulators. Granulators crush coal with a slow, positive rolling action which produces a granular product with a minimum amount of fines.

Power plants particularly choose this type of crusher for its high reduction ratio and high capacity. The product size is externally adjusted by changing the clearance between the case assembly and the ring hammers.

(4) Impactors. Impactors break the material by dropping it centrally into the path of the rotating hammers. The material then impacts against breaker plates and rebounds back into the rotating hammers. A variety of product sizes can be attained by adjustment of the breaker plates. Impactors are usually recommended for secondary and tertiary crushing applications where high reduction ratios, high capacity and a well shaped and graded product are required.

5-15.

Vibrating feeders.

granulators and hammermills and one hp per tph is used for sizing impactors.

a. General. Vibrating pan feeders consist of a

c. Coal reduction methods. Reducing coal to pan or trough to which is imparted a vibrating smaller size can be separated into the two categomotion so that material moves in a controlled flow.

ries of breaking and crushing. Breakers reduce raw

Feeders are instantly adjustable for capacity and mine coal into a manageable size, while crushers controllable from any near or remote point. Feeders break the coal down to small manageable particles.

are normally positioned under track hopper

Rotary breakers are used to crush or size run-ofopenings, the bottom of a bin or under a storage mine coal by gravity impact and are often used to pile to induce and regulate the flow of material clean debris from coal which has already been onto a belt conveyor or other means of moving sized. This type of breaker is usually used at the coal. Vibrating feeders are used for handling pracmine site and not at the boiler plant location. When tically all kinds of bulk materials, but will be used at a boiler plant, a built in hammer mill is avoided where the material has a tendency to stick included.

to the pan. The feed rate in tons per hour of the

d. Crusher types.

feeder is a function of bulk density, material size,

(1) Roll crushers. Roll crushers compress material angle of repose, angle of decline, frethe coal between a roll and a breaker plate. Teeth quency of vibration, trough stroke and feeder on the roll help to split the coal through impact and length.

toward the bottom of the breaker plate, the teeth

b. Feeder design. Feeders will be the electro shear the coal, which minimizes product fines and reduces power demand. Adjustable clearance between the breaker plate and roll determine the finished product size. The breaker plate is usually

CANCELLED debris and adjustable from outside the machine.

Roll crushers are well suited for western coal due to control on minimum size of product.

mechanical type which employ easily adjustable, rotating eccentric weights driven by a heavy duty electric motor which transmits power to the feeder pan through heavy duty springs, which in turn induces the material to flow. Electromagnetic type feeders will be avoided where possible. These type of feeders have an extremely high noise level when installed in underground pits and tunnels, and have

(2) Hammermills. Hammermills break the trouble meeting explosionproof atmosphere coal by the impact of rotating hammers throwing requirements.

the coal against breaker bars and then dragging the

(1) Each feeder will be designed and sized coal against the screen bars. This type of crusher is for nonflushing operation.

used as a primary reduction of dry or friable

(2) Hopper design and inlet arrangement to material where uniform product size is required and the vibrating feeder are very important in obtaining large amounts of fines are not objectionable.

the required capacity and preventing overloading

Hammermill crushers must be provided with a vent and choking of the pan. An adjustable depth arrangement because of the air being displaced by

TM 5-810-15

limiting gate will be provided to control the depth of material on the feeder pan.

(3) Maximum recommended feeder angle of slope is 10 degrees down from the horizontal.

Larger slopes are possible, but care must be taken to prevent the material from “flushing” (self emptying), when the feeder is shut down.

(4) The more common type of primary feeder supports consist of steel cable or bar hangers supported from the hopper or roof support steel above, with spring type shock absorbers in each hanger. A support frame can be used to support the feeder from below if the feeder cannot be supported from the hopper or overhead support steel. The feeder will be provided with at least two safety slings to prevent the feeder from falling in the event of a primary support failure. Application of suspended feeders will take into account “back out” action of the feeder.

c. Feeder construction. Feeder pan will be constructed from a minimum of 3/8-inch thick, type

304 solid stainless steel plate. Replaceable stainless steel liner plates can be used, but are far more expensive to install. Plastic type liner plates should be investigated when a sticky material is being handled.

d. Controls. There are two common types of control systems which are used to control the vibrating feed rate; Silicon Controlled Rectifier and

Variable Auto-Transformer. The control system will be capable of adjusting the feed rate from 0 to

100-percent of the vibrating feeder capacity.

(1) Silicon Controlled Rectifier (SCR). This is the more commonly preferred method of

b. Stationary type. Stationary trippers are used to discharge material at a specific fixed location into a bin or silo, or direct the material back onto the conveyor belt to the next point of discharge.

c. Motor driven. Motor driven movable trippers have the tripper frame mounted on wheels, which engage parallel rails supported on either side of the belt. This type of tripper can remain in a specific location for a short time or locked in position for longer periods. Provide a cable reel or festoon cable system to provide power to controls and motor drives. The designer must provide safety devices at each end of the tripper travel to reverse or stop the tripper car. Dust seals will be provided near the lower end of the discharge chutes to prevent the escape of dust from the covered bins or hoppers. For a clean operation hoppers or bins must be vented to release air displaced by incoming coal. Belt propelled tripper cars will be avoided.

Traveling trippers are installed in stream plants where material is discharged into multiple bins, hoppers or silos.

d. Winch type. Winch trippers have positive drives using cable connected to both ends of the conveyor, and looped up through winch. No power is required on the tripper. Winch trippers should be used when conveyor would be exposed to weather.

Wind can fold the belt which could cause a selfpropelled tripper to come off the tracks. Rain or handling material that absorbs moisture could make the rails slippery, which would not adversely affect a positive drive unit such as a winch tripper.

5-17.

Conveyor chutework.

vibrating feeder control. The SCR is a solid state,

a. Chutework design. Design of conveyor transvariable voltage, soft start control device that can fer and headchutes depends upon the accurate be used for both local and remote operation where prediction of the material trajectory path as it a manual or electronic process control signal input discharges over the end of the pulley. The curvais used. A full voltage start circuit is recommended ture of the material trajectory is dependent on the to protect against full inrush starting current.

(2) Variable auto transformer. This is a variable voltage device that is used for local, manual control of the feeder feedrate. The auto

CANCELLED dial adjustment. This type of control is being replaced by the solid state circuitry of the SCR, which is capable of both local and remote control.

material depth on the conveyor belt, the belt speed, the angle of the conveyor, pulley size and the force of gravity on the material. All the above factors should be considered during the design stage to prevent the material from choking or plugging the chutework and causing material spillage.

b. Chute slope. For good coal flow all chutework side plates will be as steep as possible but will have

5-16.

Trippers.

a. General. Tippers are used in conjunction with a horizontal belt conveyor to discharge material from the belt at points along its length. Trippers can be stationary or fixed position, arranged with suitable chutework to discharge material to either side of the conveyor or back onto the conveyor belt.

a slope no less than 55 degrees off horizontal. For western coal slope will be minimum 60 degrees, preferably 70 degrees. The designer must eliminate offsets, turns or changes in direction of chutework as much as possible.

c. Chute liners. Stainless steel or Ultra High

Molecular Weight (UHMW) liner plates will be installed on all surface subject to wear or slide, such as “dribble” from belt scrapers landing on

5-11

TM 5-810-15

chute back plates. Impact type liners or bars will be installed at material discharge impact points.

d. Construction. Headchutes and transfer chutes will be totally enclosed to reduce spillage and fugitive dust. Rubber dust curtains and seals will be provided around the conveyor belt as it enters and exits the headchute. Conveyor headchutes will have at least 2 inches clearance between the edge of the head pulley and the inside of the chute. For belt widths up to 42-inch and 48-inch through 72-inch clearance will be 3-inch. Headchute construction reclaim hopper. The hopper will be approximately

12 foot square and covered with a steel grizzly or grillage with maximum 6-inch square openings. The hopper and grillage will be designed for a fully loaded hopper and the weight of a bulldozer, frontend loader or truck. A vibrating apron or belt feeder under the hopper outlet and a manually adjustable strike off gate on the hopper regulate the amount of coal loaded onto the reclaim conveyor.

This method of coal reclaim is solely dependent on the front-end loader or bulldozer to move coal to the hopper. There is no “live” reclaim ability with this method.

c. Drawdown hopper. A more expensive method of reclaiming coal is with the use of a vibrating drawdown hopper or pile discharger. The drawdown hopper is located directly under the coal storage pile and is designed to operate on a timed cycle basis, which transmits controlled vibration energy into the coal pile, generating fracture lines, causing the control column of flow to be drawn down into the hopper and onto the conveyor belt.

should have provisions to remove the entire pulley assembly and frame so maintenance can be done in the shop. Chutework will be flanged and bolted design with externally mounted bearings and hinged access doors for ease of maintenance. Provide hinged, access doors on both sides or front (above

This method of coal reclaim can provide the plant with a certain amount of “live” reclaim from the coal pile minimizing the use of mobile coal moving machinery.

5-19.

Wet and dry dust control.

material impact point) of headchutes.

e. Chute pluggage detectors. A tilt type plugged chute detector will be furnished at each transfer point to protect the conveyor from damage. Pressure or resistance type plug chute switches are not as reliable as the tilt type switches and will not be used.

a. General. Whenever a dry material such as coal is moved or changes its direction during a process, the result is fugitive airborne dust. Fugitive dust emissions can be significantly reduced by the addition of an effective dry dust collection system,

5-18.

Coal reclaim.

wet suppression system or combination of both.

With the evolution of more stringent air pollution control regulations, coal handling systems are being required to meet these standards for the geographical area they are located in. Federal, State a. General. Reclaim systems can be classified into two categories, below grade and above grade coal reclaim systems. Small size steam plants usually cannot economically justify the types of reclaim systems employed by the larger power plants such as the above grade reclaimers, bucket wheels, boom mounted bucket wheels, barrel and bridge reclaimers, and the below grade system such as V-shaped slot bunkers, glory holes and underground reclaim tunnels with vibratory or or local clean air codes can rule out the use of one or the other types of dust control systems.

b. Wet dust suppression system. Wet dust suppression system is usually used where the dust producing area is complex, large and unconfined, such as stockpiles or track hoppers.

(1) This type of system uses a proprietary water soluble, surface active, proportioned chemical additive, to dampen and agglomerate fugitive rotary plow devices. These type of reclaim devices require a very large capital outlay. Smaller plants dust particles at the source making them too heavy to be airborne.

usually employ a combination of both the above (2) The effectiveness of wet suppression sysand below grade systems.

b. Reclaim hopper. This is the cheapest and simplest form of reclaiming coal from long term storage. In this method an above ground bulldozer moves coal from the storage pile to a below grade tems can range from total suppression in warm weather to questionable operation in cold subfreezing temperatures. Additional moisture can cause teristics of the material being conveyed, and can reduce the burning characteristics of the coal and are only as effective as the amount of dust that is contacted by the suppressing agent.

(3) A wet suppression system is a simple solution to dust control, that does not require the use of costly or elaborate enclosures or hoods, are cheaper to install and require far less space than a dry dust collection system. Changes or alterations required after startup can be made with the minimum of expense and system downtime.

5-12

(4) Foam suppression is simple and efficient.

Foaming chemicals have to be purchased. It is ideal where low moisture is necessary. Foam type systems typically add less than ½ percent moisture as compared to up to 4 percent with standard water spray systems. One foam unit is needed for each central application location. No electricity is required. Water and compressed air are required.

c. Dry dust collection systems. Dry dust collection systems utilize dry type bag filters which are designed to remove dust-laden air from unloading areas and transfer points throughout the coal handling system, as well as to provide ventilation for bins, storage silos or bunkers. The main advantage of this type of system is that it can be operated in both warm and cold climates.

(1) A dry dust collection system requires a large amount of space for equipment and ductwork, which makes it more expensive to install than a wet type dust suppression system. Operating and maintenance costs are compounded as the size of the system increases. Changes or alterations required after startup are virtually impossible without completely modifying the entire system.

Filter bag replacement for the dust collector units

TM 5-810-15

is very time consuming and costly.

(2) The collected dust from the dust collector must be returned to the material flow which allows reentrainment of the dust at the next pick-up point location.

(3) Table 5-1 shows a comparison of dry dust collection versus wet dust suppression systems.

5-20.

Conveyor safety and safety devices.

a. General. Conveying system safety begins with good design which, as far as is practical, tries to protect the operator from dangerous or hazardous areas associated with conveyors. Safety should be considered in all phases of conveyor design, manufacture, installation, operation and maintenance procedures. Conveyor operators must be properly trained and made aware of possible recognizable equipment hazards, safety procedures and devices, before they become involved in an accident. Conveyor safety is covered in ANSI B20.1. In addition, the following safety devices will be included for all conveyors:

Table 5-1. Comparison of Dry Dust Collection Versus Wet Dust Suppression Systems.

Dry dust collection Wet dust suppression Foam suppression

When recommended

Stock piles

Crushers

Enclosed transfer points

Note: Where an item is listed under both dry dust collection and wet suppression, an LCCA should be conducted to determine which system should be used.

Disadvantages

More expensive.

High operating and maintenance costs.

Changes or alteration to system are costly.

Time consuming filter bag

Large amount of space required.

Chemical additive be purchased.

Questionable cold-weather operation.

Moisture is added to coal.

Requires a water supply.

Foaming chemicals must be purchased

CANCELLED replacement.

Requires freeze protection supply.

Collected dust must be returned to the material flow.

Advantages

Enclosed hoppers, bins, silos, Open coal storage piles transfer/crusher houses.

Open or enclosed track hopper

Silo, bunker or bin venting buildings.

Op en or enclosed conveyor.

Enclosed track hopper buildings

Transfer points

Can be operated in warm and Less expensive.

cold climates.

Does not require costly or

Does not add moisture to coal.

Can be used for bin or silo venting, elaborate enclosures.

Small space required for installation.

Changes to system easily made.

Same advantages as wet dust suppression.

5-13

5-14

TM 5-810-15

b. Safety devices. Each conveyor in a conveying system will incorporate electrical safety devices to provide protection to the operating personnel as well as to prevent damage to the conveyors

* mechanical components.

(1) All electrical safety devices will be electrically interlocked so that when a “trip” signal is received from the device at the point of failure, all the downstream conveyors and feed devices, such as crushers and feeders, back to the initial conveyor feed source will shut down immediately.

(2) No conveyor can be started until the safety device has been checked and put back into proper service. Only then can the complete

i. Conveyor backstops. A backstop is a mechanical device which allows a conveyor or bucket elevator drive shaft to rotate in one direction only.

An automatic backstop will be installed on all conveyors or bucket elevators subject to reversal under loaded conditions. Backstop will be sized according to conveyor drive motor stall torque, and be provided with a removable torque arm. The backstop will be installed on the conveyor drive pulley shaft and not in the drive reducer.

j. Methane detectors. Install methane detectors and vent system anywhere that coal is stored in an enclosure.

5-21.

Spontaneous combustion of coal.

conveying system be put back into operation.

c. Emergency stop switches. Pull cord switches

a. General. A major problem with the bulk and pull cords will be located along all walkways or storage of coal is its ability to release enough heat, areas that are accessible to conveyors to protect through slow oxidation, to raise its temperature personnel from falling into any rotating or moving gradually until self-ignition or spontaneous commachinery. Once “tripped” these switches have to bustion occurs. The tendency of stockpiled or be manually reset before the conveyor can be stored coal to self ignite increases as the coal restarted.

ranking decreases.

d. Belt overtravel switches. Belt misalignment

b. Coal ranking. Lower rank coals tend to be switches will be provided on both sides of the belt very fragile, resulting in faster degradation and at the head and tail end of each conveyor and the particle size reduction during the handling process.

tripper, to detect conveyor belt misalignment,

Anthracite type coals, which are the highest ranking which can result in serious damage to expensive coals have few problems and are very easy to belts, drive equipment and structures. Extra handle. Lignite and subbituminous type coals tend switches will be installed at selected intervals, no to degrade quickly leading to spontaneous more than 500 feet apart on long conveyors.

combustion.

e. Conveyor zero speed switch. A zero speed

(1) When these types of coal are stored, switch will be provided for each conveyor in the provisions must be made to monitor the conditions system. They are installed on a nondrive pulley, in the silo, bunker or stockpile to reduce the occurpreferably the tail pulley to detect a decrease in rence of spontaneous combustion.

conveyor belt speed, from a given set value.

(2) Precautions must be taken so that mate-

f. Plug chute switches. A plug chute switch will rial in a silo, bunker or stockpile can be evacuated be installed at each conveyor transfer point. They in the event of material self ignition. Without operate when a plugged chute condition occurs, oxygen, the oxidation process cannot take place, so and are arranged to stop the downstream equipit is important that the total coal surface exposure ment from continuing to feed the plugged chute.

Similar type switches are used in hoppers, bins, silos and chute discharge points. Tilt type switches are the most common type used.

CANCELLED conveyor start sequence to warn operating or maintenance personnel that the equipment is being placed into operation. Horns will be operated for at to air be as low as possible. Coal should be stored so that air cannot infiltrate or move through the storage pile. Spontaneous combustion usually only results from careless storage procedures. Where coal is properly stored, this likelihood is remote.

5-22.

Coal bunkers.

a. General. In the design of bunkers, careful least 15 seconds, before starting any conveyor.

consideration will be given to the capacity, shape,

Provide enough horns to cover all conveyor areas bunker material, and bunker location within the in the plant.

steam plant.

h. Guards. Rotating or moving machinery which

b. Storage capacity. Bunker will be sized for a provides a safety hazard to the operator will be minimum of 30 hours supply for maximum boiler provided with a guard or guards to warn the capacity.

operator that a particular hazard does exist. ANSI

c. Shape. The shape of the bunkers are usually a

B20. 1 gives the conveyor designer guidance on compromise between space restrictions and opticonveyor safety guards.

mum design for coal flow. The more common

TM 5-810-15

bunker designs are the square upside down pyramid and silo types. Cantenary, straight, or parabolic type bunkers will not be used because the flow of coal from all outlets is not uniform which creates dead pockets and causes a spontaneous combustion hazard. Cylindrical or silo type bunkers are used to reduce danger of spontaneous ignition of coals. To reduce stagnation and coal segregation, separate bunkers will be provided for each boiler. At least the bottom of each bunker should be in the building to preclude bottom freezing. Discharge hoppers will be sloped at least 55 degrees. An emergency discharge chute will be provided for each bunker to remove coal from the bunker in emergency situations. Silo design type bunkers are more frequently used because they have been found to be less susceptible to rat holing and hangups than other shapes.

d. Material. The designer will carefully analyze the type of material being used for the bunker, to insure the material is compatible with the type of coal being stored.

e. Location. Coal bunkers should be located to provide a coal flow which is as vertical as possible.

Current trend is to replace plant storage bunkers with inside silos which require less building volume and structural support steel. On the average, it has been determined that the silo and related support steel structure were less expensive than a bunker of the same capacity. The cylindrical shape of a silo has an inherent strength advantage. A properly designed bunker generally can match a silo

*s flow efficiency, therefore such factors as moisture content, temperature and storage time have the greatest influence on the type of silo or bunker that is selected.

runoff water and leachate. Treatment facilities will be provided if required.

(3) Care must be taken in the method of constructing the coal pile. Coal is placed in maximum 18-inch thick layers and then compacted with the use of a front-end loader or rubber tired dozer to eliminate air spaces within the pile.

(4) The designer will take into account the

“weathering” process or loss of coal heating value, that takes place with long term storage of coal.

(5) Coal handling personnel will be assigned to check a long term storage pile on a daily basis, to guard against localized hot spots caused by spontaneous combustion.

(6) A liner may be required underneath the coal pile to prevent coal pile runoff from being absorbed by surrounding subsoil. Soil permeability tests will be taken in the area where the coal pile is to be located.

b. Environmental regulations. Local and State

Regulation Agencies may have environmental regulations which prohibit open storage of coal, because of fugitive dust emissions and runoff. In this case the designer should investigate the use of outside coal storage silos or covered barn structures. Both silos and barns are high capital expense items. Some agencies will allow open storage of coals with wet suppression.

5-24.

Fire protection and prevention.

a. General. Fire protection and prevention for a conveying system and its related structures, requires that the designer ensure careful planning during the initial design stage to reduce coal dust.

Fire protection systems are playing a more important role in the design of conveying systems. New

5-23.

Long term coal storage.

a. General. The long term coal storage pile is created for the sole purpose of having an adequate supply of coal on hand to supply coal to the boilers in the event of an interruption of coal supplies to the plant.

(1)

CANCELLED pile should be maintained at the boiler plant. Refer to TM 5-848-3 for the criteria for determining the quantity of coal to be stored.

coal handling system design and the suitability of the fire protection system. A fire protection system can make a difference between minor damage and total destruction.

(1) Western subbituminous type coals are less dense, more susceptible to spontaneous combustion than the eastern coals. The amount of fire protection required for any system largely depends on the type of coal to be burned at the

(2) The method of storing and reclaiming try requirements are forcing designers to reexamine facility. Some coals can be stored in bunkers for coal in an outside storage pile should be determined code standards developed by the NFPA and indusyears without any spontaneous combustion to satisfy regulatory environmental restraints.

generated fires, while other coals such as some

Drainage and collection of rainwater runoff, types of western subbituminous C type coals treatment, coal water separation and neutralizing cannot be left in a bunker for a period over 30 effluent will be included in design. Local, State and days. An emergency bunker unloading system will

Federal environmental regulations will determine be included in the design to enable the bunkers to limits for suspended solids and pH of coal pile be emptied. Western coals tend to produce a higher

5-15

5-16

TM 5-810-15

percentage of fines during the handling, conveying and stockpiling process, thus causing particles to become airborne, creating a more dusty environment. Coal dust can impair the operation of coal conveying equipment and create an unhealthy working environment which increases the risk of fires and explosions. Methane detectors and a vent system should be installed in coal storage enclosures to reduce danger of explosion.

(2) Conveyor fires are usually started by friction between seized idlers and the conveyor belt, seized bearings or improperly aligned or maintained equipment. If a fire on a conveyor should occur, the conveyor, the upstream and downstream conveyors, auxiliary feed equipment such as crushers and dust collectors must all be stopped immediately.

b. Design. The following items will be given consideration when designing a conveyor fire protection system:

(1) An automatic wet or dry pipe sprinkler system should be installed along conveyors, to protect the carrying and return belts, conveyor drives, underground tunnels and control areas.

(2) Automatic deluge systems require large flow rates to protect the conveyor and the

(9) Safety escapes. Conveyors will include means of egress that comply with all applicable codes. In no case will the distance from any location on the conveyor to a safety escape to grade level exceed 200 feet.

(10) Carbon dioxide, or steam protection should be considered for bunkers, bins and silos. A method of transporting coal from a silo to a remote yard area in the event of a fire will be considered in the design.

(11) There are numerous types of fire detection sensors and detectors such as heat, continuous thermal sensor, fixed temperature spot sensor, fusible thermal wire, pneumatic rate of rise, series thermal detector, smoke detectors, ionization detectors, flame, ultraviolet, infrared and numerous others. There is no single, all purpose sensor or detector for a fire protection system and a well designed system usually requires a wide range of sensors for maximum system protection. Matching the specific type and configuration of the detector or sensor to a particular hazard is very difficult and a professional fire protection systems engineer who has experience with the design and operation of coal handling fire protection systems should be consulted.

conveyor galleries. The water supply system will be

5-25.

Control system.

investigated to see if it can support the required

a. General. Control of the individual conveying flow rates when a fire protection system is system operations should be conducted from a determined to be necessary.

single control room. The following items should be

(3) Adequate means of removing fire protection water from below grade tunnels must be provided to ensure that personnel can be evacuated before a hazardous water build up occurs.

(4) A dry pipe or preaction type system, which employ a fusible link or glass bulb sprinkler heads, are usually used in areas that are subject to freezing conditions. This type of system is the more popular type of fire protection system.

(5) A wet pipe system, which is basically the same as dry pipe, except that water is in the system piping at all times, is usually suitable for areas not subject to freezing.

(6)

CANCELLED with pull stations at all exterior exits and sufficient evacuation alarms to overcome the normally higher level of noise found in power plants. The fire ping upstream and downstream equipment in the conveying system.

(3) A locked remote control panel will be located next to each piece of equipment they control, so that the equipment can be locally operated by maintenance personnel. Local panels will be interlocked with main control panel so that both panels cannot be operated at the same time.

(4) Each system will be adequately detection and evacuation alarms will give indication a foolproof sequential method of starting and stopmonitored with alarm and control devices so that in main and auxiliary control roams and into the down in a set sequence. The controls will provide the operating status of the system can be plant main fire alarm system.

malfunction and to shut the conveying systems determined from indicating lights on the control

(7) Adequate fire hydrant protection will be prevent coal spills in the event of a system room graphic or mimic display panel.

provided for all coal piles and consideration will be

(2) Conveyor controls will be interlocked to

(5) Indicating lights will be provided on a given to the long term methods of coal pile storage automatic control of the conveying system.

separate annunciator panel for belt misalignment, to minimize spontaneous combustion.

providing a local manual, remote manual or fully plugged chute, drive motor overload, emergency

(8) Draft barriers or fire walls will be pro-

(1) The control system will be capable of stop, zero speed, or any other safety device. The vided at each end of conveyor galleries.

considered:

TM 5-810-15

lights tell the operator at the control panel which piece of equipment has tripped and also the reason.

(6) Motor operated gates and valves will be provided in locations requiring frequent operation, and properly interlocked for starting and stopping in the proper sequence.

b. Computerized control systems. A computerized control system such as a programmable controller (PC) is the most cost effective where logic functions must be accomplished. Advances in micro technology make the cost of computer type controls more economical than the relay based control systems.

Field changes to the logic in a PC system can be made without wiring changes. Most units allow a program simulation mode, whereby the PC will diagnose the program and check the logic that has been entered. The computerized system is the preferred method of control.

5-26.

En masse conveying system.

a. General. This type of system uses a conveying chain which utilizes the skeletal flight as opposed to a paddle flight, which can greatly reduce the horsepower requirements for the conveyor. The conveyor chain runs in a completely enclosed and sealed trough. The effective conveying capacity can reach as high as 90 percent of the cross sectional area. These conveyors have the ability to convey horizontally, inclined or vertically, which makes them extremely versatile.

(1) En masse type conveyors require approximately twice as much horsepower as a regular belt conveyor to move the same amount of material the same distance. They are also very susceptible to foreign material, which is not the case with belt conveyors. Special care has to be taken when handling abrasive or corrosive materials.

(2) En masse conveyors are advantageous abrasion resistant and bolted for easy replacement.

d. Return rails. Hardness of rails will match the hardness of the conveying chain.

e. Drive sprockets. Provide a segmental type with reversible teeth sections, so that the complete drive shaft assembly does not have to be removed for maintenance. Teeth hardness will match chain hardness.

5-27.

Pneumatic conveying systems.

a. General. Pneumatic conveying involves the movement of powdered, granular or other free flowing bulk materials along the pipeline with the aid of compressed air. Pneumatic conveying can be very basically categorized into two areas—dense phase and dilute phase. Suitable materials that can become fluid-like or fluidized are usually only suitable for pneumatic conveying. The product size can also restrict the use of this type of conveying medium. This type of system is sometimes used for moving small tonnages, up to about 50 tph.

(1) Materials that have a high moisture content, such as wet coal are difficult if not impossible to handle in a pneumatic type system.

(2) Pneumatic conveying systems are extremely inefficient when comparing tonnage moved to hp required to move the material with energy consumption as much as five times that of a belt conveyor.

(3) Exotic auxiliary equipment and very costly control components have to be compared with the minimal roam requirements and ease of installation for this type of system.

b. Advantages and disadvantages.

(1) Advantages of pneumatic conveying systems are that they require little maintenance, take up less space than belt conveying equipment, are usually automatic (eliminating manual operations) and are totally enclosed, thus avoiding environmental fugitive emission problems, spillage for overbunker distribution systems, offering totally enclosed, multiple or individual discharges which do not require complicated or extensive chutework at the discharge points.

b. Chain. Use short pitch, drop forged alloy and dust.

(2) Disadvantages of pneumatic systems are that they usually have a higher operating cost than

CANCELLED steel, carburized or case hardened to 500-600

Brinell Hardness Number (BHN). Each link should be easily removable without cutting any part.

on the maximum size material and the amount of fines that can be conveyed. Coal fines in excess of

40 percent will cause pluggage problems in the

c. Trough. Provide symmetrical panels for wear and maintenance. Sides and bottom plates will be conveying pipe. Pneumatic conveying tends to create additional coal fines.

5-17

TM 5-810-15

CHAPTER 6

ASH HANDLING

6-1. General.

b. Boiler design and configuration. The boiler determines the amount of coal to be burned, and

This chapter addresses the requirements for the ash the percentage of fly ash to bottom ash. In a handling system for a coal fired boiler plant.

pulverized coal-fired boiler approximately 80 per-

a. Design criteria. Ash handling systems were cent of all ash is fly ash and the remainder 20 relatively simple prior to the enactment of stringent percent is bottom ash. In a stoker fired boiler environmental regulations during the past twenty approximately 20 to 30 percent of the total ash years. The ash was commonly quenched in wet ash content in the coal is fly ash with the remainpits and hydraulically discharged through ash sluice ing amount being bottom ash. The versatility of the trenches to a sump pit and from there were pumped boilers to burn a wide range of coals should be to an ash fill area. Bottom ash, pulverizer or mill considered to determine the highest ash producpyrite rejects (pulverized coal fired plants only), tion rate when sizing the system conveying capaceconomizer ash and fly ash are sometimes handled ity.

by individual, independent systems in plants now

c. Disposal conditions. Disposal to an ash pond being designed.

or, alternatively, to storage bins or silos is a factor

b. Methods. A well accepted method of handling in selection of equipment. Ash ponds require large bottom ash and fly ash today is by the use of areas of land and must meet environmental regupneumatic conveying systems in stoker fired boillatory restrictions. Ash storage bins require less ers. Ash is pneumatically conveyed to a storage silo space and are environmentally more compatible without coming in contact with steam or liquid.

than ash ponds; however, the ash must ultimately

Figure 6-1 shows a typical bottom ash and fly ash be removed from the bin and disposed.

conveying system. Ash dust control conditioners

d. Water availability. The availability of water have been developed to mix water with dry bottom as a source for conveying ash, its pH rating and ash and fly ash in the proper proportions to reduce other chemical characteristics must be considered.

the fugitive dust emissions during the transfer of

If the water is not recycled, the environmental ash from the storage silo to either trucks or railcars.

regulations of the discharged water must be con-

Because of higher furnace temperatures and larger sidered. In most localities, untreated overflow is ash quantities in pulverized coal fired boilers, not permitted.

bottom ash has been water quenched and

e. Type of coal. The type of coal to be burned, its hydraulically conveyed. Dry bottom ash systems ash content, sulfur content and its chemical have been limited in quantity because of dry gravity constituents have an effect on the selection of the flow. Continuous removal dry bottom ash systems ash handling system. The coal with the highest ash are becoming available and allow reconsideration of content at the maximum continuous boiler steam dry bottom ash handling. Water filled bottom ash output rating will be anticipated to assure adequate storage hoppers have been designed to accommodate large ash quantities. Bottom ash is periodically removed from the bottom ash hopper and hydraulically sluiced to an ash pond or to

CANCELLED produced in a coal fired boiler, and the ratio of fly to bottom ash depends on the coal being used, steaming rate, and method of burning. These ash handling capacity. Ash from some coals with high calcium oxide content, such as western subbituminous coal, has a tendency to solidify when it comes in contact with water and should be handled dry to the disposal areas where it can be blown underwater from a closed bed truck.

f. Design capacity. The design criteria for selection of conveying capacity will be made to require factors, along with a LCCA of available ash the system to operate no more than 50 percent of handling systems will determine equipment selecthe time or four hours in an eight hour shift. The tion. This chapter will consider hydraulic, mechanremaining time is used for maintenance or catch up ical and pneumatic ash handling systems.

time on the ash handling system. The conveying

6-2. System design.

time is based on the coal with the highest ash content which can be used in the boilers and with a

10 percent reserve margin on the estimated percent fly ash and bottom ash.

a. General. There are many considerations involved in selecting an ash handling system for a coal fired boiler plant. These are as follows:

6-1

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6-2

6-3. Bottom ash hydraulic conveying systems.

reuse. The ash ponds which act as a solid liquid separator must have a considerable area since

a. General. Hydraulic conveying systems are retention time is the only means to allow ash to generally used for only bottom ash handling syssettle and separate from the conveying water. If fly tems. Bottom ash is collected in a water impounded ash is conveyed to the ash pond, the pond must be refractory lined steel hopper, which will be sized to greatly enlarged because of the extremely slow store a minimum of twelve hours production of ash settling rate.

under the worst coal conditions at maximum

c. Dewatering bins. Dewatering bins receive the continuous boiler steam output rating. The water impounded bottom ash hopper allows ash to fall through a clinker grinder or crusher where the ash is ground to a predetermined size prior to entry into a hydraulic ejector or in some instances to material handling pumps. The ash is sluiced from the plant to ash ponds or to dewatering bins. Figure

6-2 shows a typical sluice conveyor arrangement.

The ash slurry is conveyed by a system of ash sluice centrifugal pumps. Ash handling pumps are discussed in paragraph 7-13. Most hydraulic ejectors are jet pumps requiring high pressure ash sluice centrifugal pumps to supply the water that is

CANCELLED transfer tank and the use of pumps to convey the abrasive ash slurry as shown in figure 6-3. The high pressure ash sluice pumps are also used for hopper is draining or decanting to separate the solids and liquids. The dewatered bottom ash is discharged from the bin to trucks or railcars as shown in figure

6-4. Each dewatering bin will be sized for at least

36 hour storage for a total of 72 hours storage for long weekends when trucks or rail service is not available. The dewatering bins will be designed with a 30-degree angle of repose for the ash at the top of the bins. The dewatering bins will be washdown nozzles. Low pressure ash sluice bins. While one bit receives ash slurry the other bin designed to hold the determined ash capacity at an centrifugal pumps supply water for bottom ash ash hopper the ash is pumped to two dewatering ash/water density of 62.4 pounds per cubic foot hopper furnace sealing and for coaling the refracwill be discussed. After passing through the bottom

(pcf) and be designed structurally for an ash/water tory lined hoppers, and inspection windows.

regulation, so a closed recycling dewatering system density of 110 pcf. From the dewatering bins which

b. Ash ponds. The ash ponds receive the ash most cases the discharge of water is not allowed by act as the solid/liquid separator, the decanted water slurry from the bottom ash hopper. Ash ponds must system where water is allowed to drain to waste. In with some entrained ash fines flows by gravity into be sealed to prevent seepage into ground water.

ponds, can work in a closed system or an open a settling tank for the second stage of separating

Ash ponds can be constructed in a manner to allow accumulated ash. Dewatering bins, like the ash the ash from the sluicing water. The settling tank the water to be stored and returned to the plant for ash water slurry and drain the water from the

TM 5-810-15

CANCELLED overflows into a surge tank which is the third and final stage of the closed recirculation system. The than an ash pond system. Climatic conditions may require this system to be enclosed and piping heat surge tank is sized to accommodate the overall traced to avoid freeze up problems.

coaling and conveying water demands of the bottom ash system. The decanted ash sluice water is returned to the ash conveying system for recycling. The ash sludge which is collected in the settling and surge tanks are returned to the dewatering bins by the use of sludge return pumps.

A dewatering system is much more compact but usually more expensive to purchase and operate

6-4. Bottom ash handling system alternatives.

a. Submerged drag chain mechanical transport

system. Mechanical transport systems collect bottom ash in a water impounded hopper. The hopper includes a water seal to prevent escape of the boiler furnace flue gases into the environment and to prevent ambient air from entering the boiler. The

6-3

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6-4

ash is continuously removed by a submerged

6-5. Fly ash pneumatic systems.

scraper conveyor. The ash is then conveyed to

a. Pneumatic systems. This type of system is either a storage bin with a capacity of up to three usually used to transport fly ash from the fly ash days or to a bunker for front end loader/truck collection equipment storage hoppers to the ash removal. The water is recirculated into and out of storage silo. The tendency of some types of fly ash the submerged trough to maintain a temperature to form scale inside hydraulic fly ash conveying below 140 degrees F. Overflow water from the lines and its extremely slow settling rate in water trough is filtered through tanks before it is recirwhen coupled with the environmental liquid disculated into the system. Surge tanks are small charge limitations have severely restricted the use compared to the dewatering system tanks.

of the wet type fly ash conveying system. An

b. Sizing. The submerged scraper conveyor must advantage of pneumatic systems is they can be be sized so that the rate of ash removal will be at applied to both fly ash and bottom ash for stoker least as great as ash production at maximum fired or fluidized bed boilers simplifying ash concontinuous boiler steam output rating under worst veying and storage as shown in figure 6-5. Pneufuel conditions. Mechanical transport has several matic systems are either vacuum or pressure types advantages over hydraulic transport. The ash reof system. A vacuum system pulls ash from the fly moved is dewatered, it requires a lower boiler ash storage hoppers by means of mechanical, steam setting height and reduces power and water consumption. However, ash storage in a submerged scraper conveyor is limited and maintenance must be done in a relatively short period of time.

CANCELLED pers are often needed to provide time to perform maintenance. The submerged scraper conveyor is not commonly used in the United States because or water powered exhausters and a filtering system.

Vacuum systems, depending on capacity requirements, line configuration and plant altitude may be designed for vacuum levels ranging from 8 to 20 inches Mercury (Hg). Vacuum systems are generally preferable to pressure systems because the system piping joint leaks pull air into the system leaving a cleaner environment. A vacuum system is the reliability of the system in past years has been recommended for capacities of less than 60 tph per too low. There is some renewed interest by indussystem. If the conveying distance is at a remote try in the use of this type of system because of the location of over 800 feet from the boiler plant an recent improvements in the reliability and its wider evaluation will be made to determine whether a acceptance in the European countries. Also in vacuum or pressure system is more feasible. A current use in Europe is a continuous dry removal comparison of vacuum systems and pressure system utilizing moving stainless steel belting and systems are shown in table 6-1.

introduction of additional air to complete

b. Pressure systems. A pressure system engages combustion and cool the ash.

a positive displacement blower producing pressures

TM 5-810-15

up to 20 psig for the conveying system as shown in figure 6-6. System capacity and long conveyor distances sometimes require higher blower pressures. Pressure systems may be used in lieu of vacuum systems because of higher capacities or longer conveying distances. Pressure type system should be avoided where possible because leaks of fine ash particles usually occur at the piping joints.

Silo storage design is the same for a pressure system as for a vacuum system except that ash collectors are not required at the silo and fly ash is redeposited directly into the silo. There are two types of pressure systems, the dilute phase and dense phase. The dilute phase system usually has an ash to air volumetric ratio of 15 to 1 and sometimes system, reduced to one transfer point with a minimum of controls, then delivers collected ash to any terminal point at a distance of several thousand feet. The vacuum pressure system provides the least complex controls of any long distance pneumatic conveying system.

d. Ash storage silos. Storage silos are usually constructed of carbon steel because of its lower cost and durability. Hollow concrete stave construction or reinforced concrete construction are sometimes used. The bottom of ash storage silos are equipped with aeration stones to fluidize the ash and induce flow from the silo to the discharge outlets. Silos will be designed for a minimum of sixty hours of storage, based on the design and it is as high as 30 to 1. A dense phase system has an production rate, utilizing an ash density of 60 pcf.

ash to air ratio of 40 to 50 to 1 and is sometimes as high as 80 to 1. Vacuum systems are classified as dilute phase. A comparison of pressure dilute phase and dense phase systems is shown in table 6-2. The

The actual ash density can vary from 60 pcf depending on the coals being fired. The silo support structure will be designed for a full silo with

CANCELLED dilute phase pressure system is the more widely used pressure system. Dense phase pressure systems utilize a fluidizing transporter, a vessel in

6-6. Controls

a. General. Programmable type control systems which air and ash is mixed, fluidizing the ash so are used for both automatic and semi-automatic that flow characteristics resemble that of a liquid.

control. Older systems used electromechanical type

c. Vacuum/pressure systems. In some rare cases, control systems, many of which are still in operait may be more economical to combine a vacuum tion.

system with a pressure system where distance rules

b. Types.

out the use of a vacuum system alone. Figure 6-7

(1) Programmable controllers (PC) have shows a typical vacuum/pressure system. The been applied to ash handling systems with good vacuum system, with its simplified controls, success during the last fifteen years and are the removes ash at an optimum rate. The pressure

6-5

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Table 6-1. Comparison of Pneumatic Vacuum Versus Pressure Ash Conveying Systems.

Vacuum Systems Pressure Systems

When Recommended

Convey systems less than 60 TPH per system.

Reasonable conveying distance.

High system capacity.

Long conveying distances (greater than 1000 to

2000 feet).

Advantages

Less maintenance at hoppers.

System leaks inward for cleaner environment.

Multiple collecting points.

Simpler control scheme.

Relative unlimited capacity.

Relative unlimited conveying distance.

No separating equipment.

Clean air blowers multiple disposal points.

Disadvantages

Requires separating equipment and process bag Double gates required with air lock.

filter.

Blower life dependent on separating equipment reliability.

Air lock pressurizing and venting requires additional piping and valving.

Ash leaks outward into the plant.

Higher maintenance costs.

6-6

CANCELLED most preferable type of control. The PC

*s ability to perform relay logic, timing, counting, and sequencing functions, provides a way to perform the and timing and gives him the ability to troubleshoot, modify and expand with the system.

(2) Before the advent of the PC, both the tasks required for ash handling system control. A number of higher level PC

*s also offer more enhanced capabilities such as instruction, sophisticated report generation and off-line programming. The PC performs all ash handling controls and allows flexibility in control schemes giving the user many benefits. The PC has a memory and is programmable, providing the user with the ability to change the ash handling sequence bottom ash and fly ash made extensive use of the drum sequencer, electromagnetic timers and counters, and relay logic. The disadvantage of the electromechanical system is the large amount of relay control required for the drum sequencer; the periodic maintenance required for the drum sequencer, the large amount of panel area required; the extensive wiring; and the inflexibility of the system when changes are required.

TM 5-810-15

Table 6-2. Comparison of Pressure Dilute Phase and Dense Phase Pneumatic Ash Conveying Systems.

Dilute Phase Dense Phase

Design Criteria

Evenly loaded single conveying line.

Loading ratio (5 to 22) lbs. of ash to lb. of air.

10 to 30 psig operating pressure.

2000 to 3500 ft per mm starting velocity.

Typically multiple convey lines.

Loading ratio (20 to 200) lbs. of ash to lb. of air.

30 to 100 psig operating pressure.

600 to 3000 ft per min starting velocity.

When

Recommended

High conveying capacity (greater than 30 TPH)

Long conveying distances (greater than 1000 ft).*

Multiple disposal points.

Minimum collection points.

Short conveying distances (200 to 500 ft).*

Medium capacities (10 to 50 TPH).

Minimum collection points.

Minimum disposal points.

Advantages

Greater capacities and distances with single line.

Not affected by material changes with gravity flow.

Smaller conveyor lines, bag filters and hoppers.

Lower conveying velocity.

Stable velocity range provides material re-entrainment.

Normally lower horsepower.

Transfer stations normally not required.

Carbon steel pipe.

Low initial cost air handling equipment

Components subjected to lower pressure.

Disadvantages

Higher airflow, larger pipe, and hoppers.

Often higher horsepower.

Material consistency greatly affects conveying parameters and granular material remains in

Components subjected to higher velocity, airlock with top exist.

Special pipe required-alloy pipe or ceramic lined pipe.

Positive sealing high differential discharge valve is critical to system performance.

Transfer stations normally required.

Parallel compressed air lines required to free line plugs.

Multiple conveyor lines.

Expensive initial cost air compressors.

Components subject to higher pressure.

*An evaluation should be made for conveying distances of 500 to 1000 ft to determine whether Dilute Phase or Dense Phase pneumatic ash conveying systems are more feasible.

CANCELLED

6-7

TM 5-810-15

CHAPTER 7

MECHANICAL AUXILIARY EQUIPMENT

Minimum recommended feedwater temperatures to the economizer are shown in figure 7-1. Minimum feedwater velocities are shown in figure 7-2.

7-1. General.

This chapter addresses the criteria for the major steam plant auxiliary equipment.

7-3. Steam deaerators.

7-2. Closed feedwater heat exchangers

(CFHE).

a. General. The steam deaerator (DA) heats

a. Applications. CFHE may be used to raise feedwater temperature to the plant economizer and boiler feedwater to improve plant efficiency and lowers dissolved oxygen and gasses that are corrosive to internal metal surfaces of the boiler. The thus maintain the exit flue gas temperature above the acid dew point during low load operation. This application is possible for plant design in all size standards of the Heat Exchange Institute (HEI),

1992, Fifth Edition, state that a DA should be guaranteed to remove all dissolved oxygen in ranges. Other methods for keeping the exit flue gas temperature above the acid dew point are bypassing flue gas around the economizer or excess of 0.005 cc/i.

b. Deaerator types. There are several types of steam DA with three acceptable types being: bypassing a portion of feedwater around the economizer which needs to be avoided. Bypassing the feedwater around the economizer at low load operation creates a potential for steam formation in the economizer. The CFHE is the most positive spray/tray type, atomizer or scrubber spray type and recycle type. DA heater should be counterflow design. Although some tray and recycle type DA

*s have a higher first cost, they will operate properly under rapid load changes and only require a 10 to approach to maintaining the exist flue gas temperature. An evaluation will be made to determine the economic practicality of each method.

b. CFHE design. Each CFHE will be a U-tube type heater to minimize stresses caused by thermal expansion. Tube material selection is dependent on the quality of the water. Tubes of stainless steel construction will minimize the possibility of corrosion and erosion. High quality water will

30 degrees F rise across the DA (inlet water temperature 10 to 30 degrees F lower than the DA outlet water temperature). Spray or atomizing type

DA

*s can be used when steam loads are steady and the temperature rise across the DA is 30 to 50 degrees F or greater. Because of this performance limitation, tray or recycle type DA

*s will be used unless there is a steady steam load and the temperature rise in the DA is 50 degrees F or greater. If the latter conditions exist, the DA selection will be decided by a LCCA.

allow the use of 90/10 and 70/30 copper nickel

(CuNi) material tubing.

c. CFHE design criteria. Data listed in table 7-1 are necessary to size CFHE.

c. Deaerator design criteria. Deaerating heaters and storage tanks will comply with the ASME

drop

Parameter

Table 7-1. Closed Feedwater Heat Exchanger Design

Parameters.

CANCELLED

Feedwater flow

Feedwater inlet temperature

Feedwater outlet temperature pph degrees F degrees F

Unfired Pressure Vessel Code, ASME Power Test

Code for Deaerators, Heat Exchange Institute,

American National Standards Institute, and National Association of Corrosion Engineers Recommendations. One steam plant DA can be sized for multiple boiler units. At full load conditions, the water from the DA will have a temperature sufficiently high to prevent acid dew point corrosion of the economizer. In no case will the temper-

Maximum feedwater velocity fps ature rise in the DA be less than 20 degrees F or

Maximum allowable tube side pressure psi the minimum storage capacity at normal operating level be less than 10 minutes at the DA

*s maximum

Maximum tube side operating pressure psig continuous load rating or less than 12 minutes full.

Maximum shell side operating pressure psig

Information contained in table 7-2 will be specified after a heat balance around the DA has been determined at full load conditions.

7-1

TM 5-810-15

7-2

CANCELLED

TM 5-810-15

Item

Table 7-2. Specified Deaerator Information.

Engineering Units

d. Boiler feed pump sizing. Boiler feed pumps will be sized to deliver the desired flow and pressure to the boilers from the DA. A 10 percent flow margin for wear allowance will be included when sizing the pump. These conditions are determined by first defining the items listed in table 7-3.

Maximum plant capacity

Maximum DA outlet capacity

Make-up water temperature

Condensate temperature pph pph degrees F degrees F

Make-up water flow

Condensate flow

Steam temperature to DA pph pph degrees F

Steam pressure to DA prior to control psig

valve

DA design pressure psig

DA outlet water temperature

DA outlet water flow degrees F pph

Item

Table 7-3. Boiler Feed Pumps Capacity Criteria.

Engineering Units

Boiler steam outlet pressure

Boiler water side pressure losses

Water temperature entering pump

Piping losses

DA operating pressure

Pump elevation relative to boiler and DA ft

Net positive suction head required ft

(NPSHR) psig psi degrees F psi psig

7-4. Boiler feed pumps.

a. General. Boiler feed pumps convey water from the DA to the boiler.

(1) Calculation of net positive suction head

b. Design requirements. Boiler feed pumps will available (NPSHA). Determining the NPSHA is an comply with the latest revisions of Hydraulics important design consideration for boiler feed

Institute (HI) and ANSI. A minimum of one pump pumps because they take water from the DA at per boiler and one backup pump will be provided saturated conditions. To prevent cavitation of a for all cases. The ASME Boiler and Pressure pump operating at elevated temperatures, the DA

Vessel Code requires that coal fired boiler plants in is elevated to increase the static pressure at the this size range be provided with at least two means pump suction and overcome the vapor pressure.

of feeding water. For stoker fired boilers, one

The boiler feed pump vapor pressure is equal to the source will supply sufficient water to prevent boiler

DA operating pressure and cancel out each other.

damage during an interruption. A steam turbine

Thus, boiler feed pump NPSHA is the head of driven pump is one method that is frequently used water from the DA to the pump inlet minus the to meet this requirement. Multiple pumps permit pipe friction loss. A safety margin of at least one backup capacity for individual pump failures or foot of head will be subtracted from the calculated scheduled maintenance and increase efficiency of

NPSHA to obtain the net positive suction head pump operations at reduced loads. Multiple pumps required (NPSHR).

are usually more cost effective for boilers subjected

(2) Discharge head calculation. The boiler to large daily load swings. This arrangement allows feed pump discharge head will be designed to the pumps to operate in a more efficient range and gives the system more flexibility. The use of multiple pumps will provide for between 50 and

100 percent of additional capacity beyond the

CANCELLED

c. Steam turbine drives vs electric motor drives.

Steam turbine drives provide a more thermally efficient system, but in this size range they can be overcome the boiler drum pressure, valve and piping losses within the boiler and external to the boiler as well as the head of the water column.

e. Pump construction. The boiler feed pumps will be constructed to provide continuous operation for the expected plant life. Pump manufacturers should be consulted regarding specific features of construction for a particular application. In general, lower pressures and flows could use vertical in-line less economical on a LOCA than electric motor pumps with stainless steel shaft, impellers, and drives. However, as noted above, the ASME Boiler impeller casings. Suction and discharge chambers and Pressure Vessel Code requires that both steam on vertical pumps will be cast iron. For higher turbine and motor drives be used in stoker fired pressure and flow applications casings will be 11 to bailer plants with capacities of 35,000 pph and

13 percent chrome steel, split on the horizontal above. Steam turbine drives will not be used centerline with suction nozzles, discharge nozzles exclusively. An electric motor drive makes it easier and feet on the lower half of the casing so the top to bring a boiler on line from a cold start.

half of the casings can be removed without

7-3

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disturbing the main piping. These applications will also include shafts constructed of stainless steel, containing not less than 11 percent chrome. The impellers will be of the closed type, cast in one piece. All internal parts of the pumps including impellers, sleeves and wearing rings, will be constructed of stainless steel containing not less than 11 percent chrome.

7-5. Condensate pumps.

maximum rated speed. The pump construction will include antifriction bearings that operate in an oil bath. Pump and bearing frame and housing will be constructed of cast iron. Casing will be constructed of ductile iron. Minimum casing thickness will be ½ inch with an additional 1/8 inch corrosion allowance. The shaft, shaft sleeves and wearing rings will be 316 stainless steel.

e. Turbine drives. The turbine drives will be sized to match the runout hp of the pump. Turbine drives will be horizontal split case construction.

The steam chest will be case iron or cast steel. The rotor shaft will be annealed carbon steel and the rotor disc a high strength alloy steel.

a. General. The condensate pumps convey condensate from condensate return storage tank to the

DA.

b. Design requirements. A minimum of two condensate pumps will be used, each sized for at least two thirds of the maximum steam plant demand.

This configuration will provide backup capacity for individual pump failures or scheduled maintenance and will increase pump operation efficiency at reduced loads. Steam turbine driven pumps may be more economical than electric motor driven pumps.

However, one electric motor driven pump facilitates cold start-up of the boiler plant. A LCCA will be made to determine the most practical combination of condensate pumps.

c. Condensate pump sizing. The condensate pump discharge head needs to be designed to overcome the water static head to the DA, the piping losses and the DA operating pressure. A 10 percent flow margin for wear allowance will be

7-6. Air compressors.

a. Applications. Two compressor applications are used in a steam plant: plant air and instrument air. Plant air is the dry air used to atomize fuel oil, blow soot deposits from the boiler furnace and heat recovery equipment, run plant pneumatic tools, and perform other general plant functions. Instrument air is oil free, dry air supplied to instruments and pneumatic controls control valves and control drives. Instrument air is also used to clean fly ash baghouse filter bags.

b. Compressor types. Compressors are available in two types. The first type is positive displacement, such as the reciprocating piston compressor.

The second type is dynamic, such as the centrifugal included when sizing the pump. The condensate pump discharge head and suction head available will be determined when the operating conditions are defined, an arrangement of the equipment has been made, and a pipe size and routing has been made.

compressor. Each type can be furnished with single stage or multiple stage design. Reciprocal and centrifugal compressors are the industry standard for compressors used in boiler plants. Centrifugal compressors are usually considered for selection when the compressed air demand is uniform and is

d. Pump construction. Pumps will be constructed so they will provide continuous operation for the equal to or above 400 standard cubic feet per minute (scfm). Otherwise reciprocating comexpected plant life. Pump manufacturers should be pressors are usually used.

consulted regarding specific features of construction for a particular application. The pump impellers will be split ring key type. Bearings will be of the water lubricated sleeve type. The baseplate, outer barrel, inner column and discharge

c. Instrument air compressor sizing criteria.

(1) Required volume of air. The required volume of air needed is found by adding all simultahighest usages generally occur during boiler start head will be carbon steel. The impeller will be bronze and the pump bearings graphalloy. The stage bowl will be cast iron. The shaft, shaft sleeves and wearing rings will be 11 to 13 percent chrome stainless steel. When the pump design conditions do not require a vertical can type pump as described above, the pump may be centrifugal, horizontal end suction, top discharge type as described below. The pump impellers will be totally open type, screw mounted directly to the shaft with

0-ring seal and constructed of ductile iron.

Impellers will be dynamically balanced to the up when lighters are inserted or when fly ash baghouse filter bags are being cleaned.

(2) Outlet pressure. The compressor outlet pressure will be sufficient to supply air at the required pressure, after line losses, to the device requiring the highest pressure in the instrument air system. Pressure regulators will limit the pressure to devices operating at lower pressures.

d. Plant air compressor sizing criteria.

(1) Required volume of air. The required volume of air needed is found by adding all simultaneous air usages together. One of the highest

7-4

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usages of plant air occurs when air soot blowers are used in the boiler. Steam soot blowers may be used eliminating the need for air soot blowers.

Other usages which must be considered are air tool demand and cleaning coal handling dust bags.

(2) Outlet pressure. The compressor outlet pressure will be sufficient to supply air at the required pressure, after line losses, to the device requiring the highest pressure in the plant air system. Pressure regulators will limit the pressure to devices operating at lower pressures.

e. Compressor auxiliaries.

(1) Aftercoolers/intercoolers. Intercoolers are used on any compressor having more than one

(4) Plant air compressor will be designed to be loaded 50 percent of the time at maximum load.

Instrument air compressor is to be sized for 40 percent loading at maximum load. Centrifugal compressors can be loaded 100 percent of the time.

(5) Provisions will be made to allow drainage of water from all coolers and receivers by means of traps or manual valving.

(6) Separate receivers will be placed near area of large air demands. It may be more economical to supply separate air systems for air soot blowers and baghouse cleaning systems.

7-7. Boiler feedwater treatment.

a. General. Feedwater treatment is necessary to prevent corrosion of metals, formation of deposits stage, and all compressors will have aftercoolers.

Aftercoolers will be pipeline type units with air-intube, water-in-shell construction and designed with and to minimize boiler water solids carryover.

Boiler water treatment guidelines are discussed in

AR 42049. For boilers operating at 400 psig, a 20 degrees F approach.

(2) Air dryers. All air compressors will have air dryers installed immediately downstream of the constituents in the feedwater must be controlled so that the maximum water limits for boiler feed-water and boiler water shown in tables 7-4 and 7-5 can be aftercoolers. The dryers will be designed to maintain a dew point at line pressure which is lower than any ambient temperature to which pressurized maintained with minimal boiler blow-down, since the higher the blowdown rate, the greater the air lines are exposed.

(3) Receivers. Receivers will be sized based thermal loss. An evaluation will be made to determine the costs of thermal losses due to blowdown versus the costs of high quality treated upon a timed usage of a volume of air. The required tank volume will be determined using equation 7-1:

T

' V x (P

1

& P

2

)

(eq 7-1)

C x P

0

T = time in minutes receiver will supply air from upper to lower pressure limits (use 15 seconds) water.

Drum

Pressure

Table 7-4. Boiler Feedwater Limits.

Iron Copper

Total hardness

Calcium

carbonate

V = volume of tank, in cubic feet

P

0

= absolute atmospheric pressure, psia

P

1

= maximum tank pressure, psia (compressor discharge pressure)

P

2

= minimum tank pressure, psia (pressure required to operate tool)

(psig)

0-300

3010-450

(ppm Fe) (ppm Cu)

0.100

0.050

0.050

0.025

Table 7-5. Boiler Water Limits.

0.300

0.300

C = amount of cubic feet of free air needed per minute, cfm (air at ambient temperature and pressure)

CANCELLED

(1) The total air capacity will be increased by a factor of 1.1 to 1.2 to account for leakage.

(2) Both the instrument air and the plant air

Drum Silica

Total

Alkalinity

calcium

301-450 90 600

Specific pressure silicon dioxide carbonate conductance

(psig)

0-300 150 700 7000

6000 systems will consist of two compressors tied to a common header. Backup capacity of 100 percent will be provided so maximum compressed air demand can be satisfied with one compressor out of service.

(3) The headers for instrument air and plant air will have an emergency cross-connection equipped with oil removal equipment to protect the instrument air system.

b. Design requirements. Before a plant water treatment system is designed, a thorough raw water analysis will be obtained as shown in table 7-6.

The raw water condition can vary widely even within a small regional area and can greatly effect the options and economics available for water treatment equipment. Also, the purity and quantity

7-5

7-6

TM 5-810-15

of condensate available as feedwater is to be established. From this information the actual feedwater constituents to be treated can be determined. The water treatment requirements for the plant can then be identified based on the allowable boiler water limits and the desired amount of continuous boiler blowdown (use 1 percent of boiler maximum continuous rating as a starting blow-down value).

Calcium

Silica

Sodium

Sulfate

Chloride

Nitrate pH

Table 7-6. General Raw Water Analysis.

Water properties

Magnesium

Bicarbonate

Total hardness

Carbonate hardness

Noncarbonate hardness

Total alkalinity

Conductivity - microseim per per centimeter

Milligrams/Liter

As the ion or as

Shown

64.5

9.1

20.7

70.0

182.0

23.3

211.0

4.0

248.0

173.0

73.0

166

731

8.2

Note: Water characteristics will vary by location.

c. Treatment. Water treatment is generally categorized by external treatment or internal treatment.

External treatment dampens, softens, or purifies raw water prior to introducing the water into the water where they regulate the undesirable effects of water impurities. Blowdown is used in the evaporative process to control the concentration of dissolved and suspended solids. Methods of water treatment include filtration (reverse osmosis), deaeration (para 7-3 above) and degasification, cold or hot lime softening, sodium zeolite ion exchange, chloride cycle dealkalization, demineralization, internal chemical treatment, and blowdown. Several internal treatment methods commonly used to treat boiler water include phosphate hydroxide or conventional treatment method, chelent method, polymer method (feedwater < 1.0

ppm Ca as Ca CO ), and coordinated phosphate/pH

(high purity

# 15 mirohms conductivity). These chemical internal treatment methods can be used in conjunction with external treatment methods. After a raw water analysis has been made, a water treatment specialist should be consulted and an evaluation should be made on the practicability of a combination of internal and external treatment methods. It is usually more cost effective to externally pretreat the feedwater as much as practical. This discussion concerns boiler feedwater treatment equipment. It is assumed that water delivered to the feedwater equipment is of a pretreated, clear, potable quality free of organic materials.

d. Boiler feedwater treatment equipment. The industry standards for reducing water constituents in boilers with an operating pressure of 400 psig are reverse osmosis, ion exchangers, or combinations of the two.

(1) Reverse osmosis (RO) is a filtration method which removes approximately 90 percent of all inorganic dissolved solids from the feedwater.

Reverse osmosis can be used alone, as shown in figure 7-3, but is more generally used with regenerative ion exchange equipment (demineralizer) as feedwater system. Internal methods introduce shown in figure 7-4. The viability of using reverse chemicals directly into the feedwater or boiler osmosis will be determined by a LCCA.

CANCELLED

(2) Sodium zeolite (NaZ) softeners are used to remove calcium (Ca) and magnesium (Mg) from the feedwater. NaZ softeners do not remove silica, bicarbonate, or carbonate, and should be used alone when these constituents are not a problem in the boiler feedwater. A typical NaZ softener is shown in figure 7-5.

(3) A split stream softener with degasifier should be used when it is necessary to remove

2 formed from bicarbonate and carbonates. A typical split stream system is shown in figure 7-6. The use of split stream versus other options will be decided by means of a LCCA and an evaluation of applicable safety restrictions. This particular type system will result in a reduction of total dissolved solids

(TDS).

(4) Chloride anion exchangers

TM 5-810-15

(dealkalizer) may be used in conjunction with NaZ softener to remove carbonate, bicarbonate and place of a hydrogen cycle softener and degasifier in the split stream system. A dealkalizer application is shown in figure 7-7. This particular type system will not reduce TDS.

(5) A weak cation exchanger, regenerated with acid, followed by a strong acid cation exchanger, salt regenerated, can be used in conjunction with a degasifier. The weak acid exchanger will remove the alkalinity and the hardness associated with alkalinity, and the salt regenerated strong acid cation exchanger will remove the balance of the hardness. This balance will depend on. the hardness to alkalinity ratio of the raw water. The the weak acid exchange process.

CANCELLED

7-7

TM 5-810-15

7-8

(6) Demineralizers produce very high quality water—higher than is generally required for a boiler operating at 400 psig.

either intermittent or continuous operation is used to control concentrations of dissolved solids. It is

CANCELLED

7-8. Blowdown tank.

a. Application. Pure water vapor is generated in boiler in such location as to minimize the inclusion of feedwater, chemical feed and steam entrainment.

The other blowdowns from the mud drum or the water walls are intermittent or mass blowdowns a bailer and the impurities (dissolved solids) of the which removes accumulated solids and sludge from boiler feed water remain and become concentrated.

stagnated areas of the boiler, usually at reduced

The concentration of dissolved solids can be steam loads. A blowdown tank allows the hot controlled by withdrawing the boiler water with a water to flash to steam leaving the concentrated high concentration of dissolved solids as blowdown impurities to be more safely drained to waste. The and discharging it safely to waste through a flashed steam can be vented to atmosphere or can blowdown tank. Every boiler - system has two be used in a heat recovery system.

types of blowdowns. The upper blow-down of

b. Design.

(1) Blowdown tanks will be designed and constructed in accordance with the ASME Boiler and Pressure Vessel Code, Section VIII. The amount of boiler blowdown capacity is determined to be a percentage of the boiler firing rate. The percent of boiler blowdown is governed by the allowable concentration ratio (CR) or the number of times a dissolved solid may be concentrated over the amount of dissolved solid in the feedwater. The allowable concentration ratios are determined by a chemical analysis of the boiler feedwater and by the type of makeup water treatment. The continuous blowdown rate can be determined using equation

7-2:

R

'

B

A

&B x Q

(eq 7-2)

Boiler

Design

Pressure

(psig)

20 to

50

51 to

100

101 to

150

151 to

200

201 to

300

301 to

400

Table 7-7. Blowdown Tank Size.

*Blowdown

Size

(Inches)

¾

1

2

¾

1

2

Cold

Steam

Vent

Size

(Inches)

3

4

2

2

2

2

4

5

3

6

Water

Inlet

Size

(Inches)

2

2

¾

1

1

2

¾

1

2

6

8

4

5

3

1

2

3

¾

1

2

¾

1

2

¾

1

2

3

4

5

6

8

1

2

2

2

3

4

4

2½ 8 3 5

4

5

6

6

8

10

2

3

3

4

5

6

2

4

4

5

6

8

10

10

2

3

4

4

5

3

4

6

3

4

2

3

4

5

4

4

2

3

5

Water

Outlet

Size

(Inches)

4

4

TM 5-810-15

R = Blowdown rate (pph)

A = Predetermined bailer water concentration as total solids (ppm)

B = Total solids in feedwater to boiler (ppm)

Q = Steam output (pph)

A boiler operated on exceptionally high quality feedwater will have very little blowdown. The size of the blowdown tank will be determined from table 7-7. Blowdown, steam and water connection sizes are shown in table 7-7. The tank will have openings to allow cleaning and inspection. The blowdown tank should have a blowdown inlet connection, a water outlet connection, a vent connection, a cold water supply line, a drain connection, a thermometer connection, and a pressure gauge.

**Blowdown

Tank

Size

(Dia x Ht.)

14” x 5'6”

14” x 5'6”

14” x 5'6”

14” x 5'6”

18" x 6

*0”

20” x 6'0

14” x 56”

14" x 5

*6”

18” x 6

*0”

18” x 6

*0”

24" x 6

*0”

30" x 6

*6”

14” x 5

*6”

14” x 5

*6”

20” x 6

*0”

24” x 6

*0”

33” x 6

*0”

39” x 66”

14" x 5

*6”

18” x 6

*0”

24” x 6

*0”

30" x 6

*6”

39" x 6

*6”

48” x 6'6"

18” x 60”

24" x 6

*0”

30" x 6

*6”

36" x 6

*6”

48" x 6

*6”

54” x 7

*0”

20" x 6

*0”

24” x 6'0"

33” x 6

*6”

42" x 6

*6”

54" x 7

*0”

66” x 7

*0”

7-9

7-10

TM 5-810-15

Table 7-7. Blowdown Tank Size. (Continued).

Boiler

Design

Pressure

(psig)

401 to

500

501 to

600

601 to

800

801 to

1000

1001 to

1500

1505 to

2000

2001 to

2500

Water

Outlet

Size

(inches)

4

4

5

4

5

5

5

6

4

4

3

4

5

6

3

4

5

6

8

3

4

4

5

8

3

4

5

6

8

Water inlet

Size

(Inches)

2

3

3

3

4

2

3

4

2

3

2

3

4

3

4

Cold

Steam

Vent

Size

(Inches)

8

10

10

12

8

8

10

12

8

10

12

12

6

8

10

10

12

5

6

8

10

12

12

8

10

12

4

5

8

5

6

8

10

12

12

*Blowdown

Size

(inches)

¾

1

¾

1

¾

1

2

¾

1

2

¾

1

¾

1

2

¾

1

2

**Blowdown

Tank

Size

(Dia x Ht.)

30” x 6

*6”

42" x 6

*6”

54" x 7

*0”

66" x 7

*0”

72" x 7

*0”

36" x 6

*6”

48" x 6

*6”

66" x 7

*0”

72” x 7

*0”

42" x 6

*6”

48" x 6

*6”

66” x 7

*0”

72” x 7

*0”

48” x 6

*6”

66” x 7

*0"

72” x 7

*0”

72" x 7

*0”

20” x 6

*0”

27” x 6

*6”

39” x 6

*6”

48” x 6

*6”

60” x 7

*0”

72” x 7

*0”

24” x 6

*0”

30" x 6

*6”

42” x 6

*6”

54” x 7

*0”

66” x 7

*0”

72” x 7

*0”

27” x 6

*6”

36" x 6

*6”

48” x 6

*6”

60” x 7

*0”

72" x 7

*0”

72" x 7

*0”

*Size of blow-off connection on boiler or size of blow-off header, whichever is larger.

**The sizes tabulated are based on the minimum diameter and minimum volume that can be used. Larger diameter tanks with equivalent or larger volume may be used.

(2)

CANCELLED tank will have a wear plate between the tank water level and the top of the tank. The blowdown will enter tangentially and the wear plate attached to the blowdown equipment will not exceed 5 psig. The

Boiler Law and Rules & Regulations Code administered by the Bureau of Safety & Regulation in

Lansing, Michigan can be used as a guide in designing blowdown tanks. Each state will be consulted to determine their design criteria.

shell at the point of impact from the blowdown.

The wear plate will be the same thickness of the tank and extend approximately one-third of the tank circumference. The blowdown tank vent will allow steam to escape from the highest possible location on the tank and will be as direct as possible to the outside atmosphere without intervening stop valves. The water discharge

7-9. Slowdown heat recovery.

a. Application. A LCCA will be conducted to determine if a blowdown heat recovery system is a justifiable capital investment.

TM 5-810-15

Table 7-8. Blowdown Tank Pressure.

Maximum Allowable Boiler

Pressure, psig

50

100

200

300

500

750

1000

1500

Blowdown Tank Design

Pressure, psig

125

165

200

275

25

50

70

90 stainless steel tubes, outer tubes 1 inch outside diameter and 0.049-inch minimum wall thickness and inner tubes 5/8-inch outside diameter and

0.022-inch minimum wall thickness. The supply and return connections are to be on the same end of the coil. Tubes will be pitched to the drain. The coil should be removable in a manner that does not disturb connecting ends of breeching. The coil outer casing is typically 10 gauge steel welded into an airtight structure. The core header plate will be gasket sealed to the casing.

7-11.

Steam coil drain tank.

2250

2500

325

400

b. Design. Heat is recovered in a blowdown heat recovery system by passing the blowdown water from the blowdown tank through a heat exchanger to recover the sensible heat of the water and transferring blowdown tank steam to the DA. The heat exchanger will be sized to reduce the temperature of the blowdown main to 20 degrees F above the inlet temperature of the fluid being heated, typically feedwater heating, makeup water heating, building heating, oil heating or process steam generation. The blowdown tank for a heat recovery system will be smaller to allow the blowdown drain water to be hotter for an effective heat recovery system. If flash steam is used in the DA, the blowdown tank will be designed to minimize

a. Application. The steam coil drain tank will collect the condensate from the steam coil air heater for transfer to the DA.

b. Design. The steam coil drain system must be sized large enough to drain the maximum expected steam flow rate to the air heater and to maintain a reasonable condensate level allowing proper operation of the steam coil drip return pumps (if included). Another consideration is the possibility of freezing. The steam coil tank should be located indoors, if possible, and sized small enough that outdoor drain piping is not allowed to fill with condensate. The steam coil drain tank is normally equipped with a level controller, gauge glass and high level alarm. The steam coil drain tank will be designed and constructed in accordance with the

ASME Boiler and Pressure Vessel Code, Section

VIII.

carryover. A normal blowdown system consisting

7-12.

Fans.

of a large blowdown tank venting to atmosphere

a. Applications. Boiler furnaces are either presand draining directly to waste may have to be surized or have balanced draft for combustion. Gas available to allow maintenance on the heat recovery and oil fired boilers are normally of the pressurized equipment during operation. There are several furnace design. Modern coal fired boilers have package blowdown heat recovery systems available balanced draft type furnaces. Balanced draft type consisting of blowdown tanks, heat exchangers, boilers use FD fans to supply combustion air to the flow control valves, thermostatic control valves, sample coolers and high level float switches.

7-10.

Steam coil air heater.

CANCELLED heater. The heat dries the air and reduces corrosion of the air heater tube metals.

b. Design. The installation will be designed for furnace and ID fans exhaust the products of combustion or flue gas. The furnace is kept at a slightly negative pressure ranging from 0.1 to 0.25inches w.g., by the ID fan which is located downstream of the particulate removal equipment.

b. Forced draft fans. FD fans operate with reasonably clean, cool or warm air and will be designed for quietness and efficiency. This source of combustion air is frequently taken from within reasonable air velocities with pressure loss not to the steam plant to promote ventilating and to take exceed one inch of water. The heating coils will be advantage of the higher ambient temperatures.

designed in multiple elements to maintain average

Inlets for the fans will have silencers with screens cold and metal temperatures of the air heater to attenuate entrance noises and to keep birds and surfaces above 180 degrees F at all loads up to 15 other objects from entering the system. The static percent above full rated load. The uncorrected air pressure of the FD fan will be calculated for the heater gas outlet temperature should be used to pressure drop through the inlet air duct, steam coil determine the average cold end metal temperature.

air heater, air heater (if used), air metering devices,

A typical steam coil would have seamless type 321 dampers or vanes, air ducts, static fuel bed or

7-11

7-12

TM 5-810-15

burners and any other resistance between the fan and the furnace at the air flow rate required for proper combustion. The volume of the air to be handled is dependent on the air pressure

(elevation), moisture content if moisture exceeds 1 or 2 percent by weight, temperature and excess air required. Factors of safety to be added to the air flow requirements to obtain test blockrating are 20 percent excess volume and 32 percent excess pressure for coal fired boilers. Add 25 degrees F to temperature of the air being handled as a safety factor.

(1) FD fan will be airfoil type to provide lower power consumption. Airfoil fans will have inlet vane controls to provide low part load power consumption.

(2) FD fan design will include the following features. Shafts will be designed to have critical speeds not less than 1.4 times the operating speed.

Bearings will be antifriction type with L10 life of

100,000 hours. Wheel stresses should not exceed

50 to 60 percent of yield strength while using finite difference methods and 75 percent of yield strength entering gas being handled as a safety factor. ID fan type will be selected based on grain loading according to table 7-9.

0.1 to 0.2

>0.2

Table 7-9. ID Fan Type.

Grains/actual cubic feet

ID fan control type will be selected based on temperature and grain loading according to table

7-10.

Temperature

#500 F

>500 F

Radial tipped, backward inclined, or radial bladed

Table 7-10. ID Fan Control Type.

Grains/actual

cubic foot

#0.2

>0.2

ID fan type

Airfoil

Type ID fan control

inlet vane inlet box dampers at operating temperature while using finite element

ID Fan design will include the following features.

methods. Stress rupture should be considered for

Shafts will be designed to have critical speeds not elevated temperature. Variable speed fan fatigue less than 1.4 to 1.5 times the operating speed.

life should be evaluated to avoid premature failure

Bearings shall be antifriction type with L10 life of due to low cycle fatigue. An impact response test

100,000 hours. Partial liners will be included for should be performed to avoid high cycle fatigue airfoil or backward curved fans. Partial or full due to resonance. Resonance speed of fan support width liners will be included for other blade types system should not be less than 1.2 times operating based on dust loading and velocities. Housings will speed.

be provided with liners or replaceable heavier scroll

c. Induced draft fans. ID fans can operate under for fans with severe dust loading. Wheel stresses erosive conditions even though these fans are should not exceed 50 to 60 percent of yield located downstream of the particulate (fly ash) strength while using finite difference methods and collection equipment. Erosion is controlled by us-

75 percent of yield strength at operating temperaing abrasion resistant material and limiting top ture while using finite element methods. Stress speed. The ID fans move the gas from the furnace, rupture should be considered for elevated temperathrough the superheater if required, boiler bank, ture. Variable speed fan fatigue life should be economizer, ductwork, scrubbers, baghouse and stack. Corrosion must be considered if temperatures of flue gas are within 30 degrees F of the dew point. The type of fan is usually straight radial with

CANCELLED strips when dust burden is high. Maximum speed should be 1200 revolutions per minute (rpm). Even when flue gases are normally cleaned through a evaluated to avoid premature failure due to low cycle fatigue. An impact response test should be performed to avoid high cycle fatigue due to resonance. Resonance speed of fan support system should not be less than 1.25 times operating speed.

d. Fan control methods.

(1) Dampers are used on the fan discharge at either the stoker plenum, the boiler outlet or in ducting and function to raise system resistance, baghouse before they reach the fan dirty gases can thus raising operating points higher on the fan be bypassed around the baghouse and impinge on curves and altering fan output. Input power can the fan blades or wheel. Therefore, the fan must be decrease somewhat on decreased volume output if constructed to resist fly ash and dust buildup and to fan efficiency increases. Dampers are closed on give better wear resistance. Factors of safety to be startup of the boiler to reduce the starting load on added to the air flow requirements to obtain test the motor.

block rating are 20 percent excess volume and 32

(2) Variable inlet vanes are used to change percent excess pressure for coal fired boilers. Add characteristic curves of FD fans. Vanes impart a a minimum of 25 degrees F to the temperature of prespin to the gas and by the alteration of the pitch

TM 5-810-15

of the vanes, fan discharge volume and pressure are changed to give new system operating points. With fixed speed motors, power usage only slightly diminishes as air volume is reduced; this system will operate economically if air volume is 75 percent or above the design volume. Movement of vanes is non linear so they have to move more at low loads.

(3) Two speed motors, generally of speed ratios of 4:3 or 3:2 with variable inlet vanes will provide economical operation down to 40 percent of the design volume.

(4) Variable speed drive on ID fan, two speed or variable speed motor on FD fan, with variable inlet vanes on boiler outlet damper, are generally required for most efficient operation of heating plant boiler systems with power drive requirements in excess of 10 hp. The benefits of a variable speed drive are greater when the boiler is operated at lower loads. A life cycle cost analysis

(LCCA) should be performed based on the number of hours at each load to justify the use of a variable speed drive. The variable speed gives an infinite series of fan curves from which the points of highest system efficiency can be chosen. Fans with both adjustable speed capability and control inlet vanes provide the most energy efficient operation.

Control dampers may be provided for multiple coal fired units with auxiliary oil firing for startup of boiler and adjustment of air flow. If oil is fired in a boiler designed for coal firing, excessive dampering may set up objectionable vortexing of the air currents in the breeching and ductwork unless variable speed drives are used in the system.

e. Fan motors. Motors will be selected for the maximum duty required by the fan under most severe anticipated operating conditions. Motor selection is discussed in chapter 10.

7-13.

Hydraulic ash handling pumps.

required to make available adequate NPSH for an effective pump.

(3) Construction. The pumps will be constructed in a horizontal split case configuration with a heavy duty slurry type enclosed impeller.

Replaceable shaft sleeves, suction sideplates and rear sideplates will be provided. The pump will include oil lubricated bearings and a stuffing box packing for external clean water injection.

(4) Pump materials. Ash sluice pumps will be designed of abrasion resistant alloys to provide an acceptable life.

c. Bottom ash pump.

(1) Application. The bottom ash pump transfers the slurry from the bottom ash hopper discharge to a disposal area, either dewatering bins or ash handling ponds. The bottom ash pump is not needed if the ash sluice pumps are designed to pump the water through the hopper discharge to the disposal system.

(2) Sizing. The bottom ash pump is most generally used with a surge tank downstream of the ash hopper offering a controlled NPSH. Two 100 percent capacity pumps will be used to provide full backup. The capacity of the bottom ash pumps depend on the hydraulic ash handling system demands. The capacity must be greater than the ash sluice pump capacity. The discharge head of the bottom ash pump will be designed to overcome the piping losses and static head to a dewatering bin.

(3) Construction. The pumps will be constructed in a horizontal, vertical split case, end suction back pullout configuration with a heavy duty, slurry type enclosed impeller. Replaceable shaft sleeves, suction sideplates and rear side-plates will be provided. The pump will include oil lubricated bearings and a stuffing box packing for external clear water injection.

(4) Pump materials. Bottom ash pumps will

a. Application. Bottom ash can be conveyed hydraulically from a bottom ash hopper by means of mechanical pumps. Hydraulic ash handling systems are discussed in chapter 6.

b. Ash sluice pump.

CANCELLED

(1) Application. The ash sluice pump pumps recycle sluice water through the bottom ash hopper outlet to be disposed.

an acceptable life.

d. Ash sluice water recirculation pumps.

(1) Application. Ash sluice water recirculation pumps are used for returning ash pond water to a surge tank for the ash sluice pump suction.

(2) Sizing. Two 100 percent capacity pumps will be used to provide full backup. The capacity of

(2) Sizing. Two 100 percent capacity pumps the recirculation pumps must exceed the ash sluice will be used to provide full backup. The capacity of be designed of abrasion resistant alloys to provide pump capacities. The NPSH available will be the the ash sluice pumps will depend on the hydraulic atmospheric pressure of the ash pond plus the ash handling system demands. The discharge head depth of the impeller minus the resistance of the of the ash sluice pump will be designed to oversuction bell piping. The discharge head of the come the piping losses and static head to a recirculation pumps must overcome piping losses dewatering bin or surge tank. A jet pump hydraulic and the surge tank static head.

system will demand higher pressure pumps to allow the jet pump to function properly. A surge tank is

7-13

7-14

TM 5-810-15

(3) Construction. The pumps will be vertical shaft configuration with bottom suction. Replaceable suction sideplates and rear sideplates will be provided.

(4) Pump materials. The ash sluice water recirculation pumps will be designed of abrasion resistant alloys to provide an acceptable life.

e. Sludge return pump.

(1) Application. The sludge pump is used on a hydraulic ash handling system using a dewatering bin. A tank or series of tanks collect and store the water discharge from the dewatering bins. Remaining ash particles settle in these conical shaped tanks and are pumped from the tank bottom back to the dewatering bins by sludge return pumps.

(2) Design. The sludge return pumps have the same design characteristics as the bottom ash pumps.

absorbed by the clean bearing cooling water and transfer it to a circulating water system. The circulating water system may use river water, lake water, or a cooling tower system where absorbed heat can be discharged. An evaluation must be made to determine the feasibility of using a heat exchanger versus using a cooling tower where bearing water is directly pumped through the cooling system. A plentiful supply of dirty water from a lake or river may make a heat exchanger more economical. Consideration will be given to water treatment as a cooling tower bearing water system would have to be constantly monitored and treated as water is made up for evaporation.

b. Design. The heat exchanger must be sized to transfer all the heat generated from the fully operational plant at the maximum continuous rating. Two heat exchangers will be used so one can be removed from service, each having 100 percent of the flow capacity. The heat exchanger

7-14.

Bearing cooling water pumps.

a. Application. Bearing cooling water pumps will supply cooling water to all plant equipment with a will be designed to conform to the ASME Boiler and Pressure Vessel Code, Section VIII. The heat exchanger manufacturer must be given the inforcooling water demand. Typical equipment requiring cooling water are pulverizers, pump bearings and mation for both the shell side and the tube as shown in table 7-11. The amount of cooling water seals, air compressors and after coolers, fan drives, lube oil coolers and chemical feed sample coolers, boilers access doors and scanning fire detectors.

required depends on the equipment cooling water demand. The equipment manufacturers will be asked how many gallons of cooling water per

Smaller boiler plants may have processed water available and may not require cooling water pumps.

Boiler plants with a plentiful water supply will minute is required for equipment cooling at a given inlet temperature of 95 degrees F allowing the outlet temperature to be no more than 10 degrees sometimes allow cooling water to be discharged without recirculation.

b. Design. Two 100 percent capacity pumps will

F higher. The heater cooling water rated flow capacity will be the total equipment demand of all equipment to be operating simultaneously plus a 20 percent design margin. The circulating water rated flow capacity will be twice the cooling water rated be used to provide full backup. The required flow rate needed is found by adding all equipment coincident demands. The future expansion of the flow capacity.

plant will also be considered. The cooling water system may be an open (once through) or closed

c. Construction. The coolers will be designed

(recirculating) type of system depending on the availability of clear water. The system head required must be determined by adding the system piping friction losses and the static head required.

CANCELLED allowance. This will be the rated capacity and total dynamic head for the pump selection.

c. Construction. The pumps will be motor and constructed to conform with the ASME Boiler and Pressure Vessel Code, Section VIII. The

Table 7-11. Heat Exchanger Design Information.

Typical Values

Shell Side

Cooling Water

Tube Side

Water

Number of passes .1

1 driven, horizontal, vertical split case, end suction,

Temperature in, degrees F 115 85 centrifugal type, back pullout configuration, single

Temperature out, degrees F 95 95 stage design.

Flow gpm.

demand demand

2 5

7-15.

Bearing cooling water heat exchangers.

Maximum pressure drop,

psi

a. Application. Bearing cooling water heat exchangers are required for a closed loop system in which clean water is not available in unlimited quantities. A heat exchanger will transfer heat

Design pressure, psig

Fouling factor

Maximum velocity, fps

150

.0005

3.0

75

001

5.0

construction of the coolers will allow the circulating water or dirtier water to pass through the tubes allowing more practical cleaning. The cooler tubing and tube sheet material selection will be based on water quality. Materials can be admiralty, copper nickel, or for corrosive applications stainless steel. The coolers will be the straight tube type with fixed tubesheet, removable channel construction. The shell will be carbon steel and the channel heads will be fabricated steel. The shell will have 150 pound raised face flanged or

3000 pound screwed connections. The channel will have 150 pound flat faced flanged or 3000 pound screwed connections. The coolers will be manufactured with shell, channel vent and drain connection.

TM 5-810-15

mendations of the boiler manufacturer. Depending on the boiler and down period, such steam parts filled with treated water or a nitrogen purge are the economizer, water walls, superheater, reheater, feedwater heater (tube side-water; shell sidenitrogen) and drum. In some cases freezing may be a problem and treated water can be replaced with nitrogen. The amount of nitrogen required, for boiler purging will be given by the boiler manufacturer or can be calculated from the volume of the steam parts. The nitrogen system is a low pressure system. However, the nitrogen is stored in high pressure cylinder bottles and the piping will be connected to a high pressure boiler. A pressure regulator and high pressure valving will be required.

7-16.

Ignitor fuel oil pumps.

7-18.

Carbon dioxide (CO ) system.

a. Design. Ignitor fuel oil pumps will be rotary screw type pumps. Two pumps will be provided, each rated at 100 percent capacity, with one pump used for backup service. A fuel oil unloading pump will be applied if required and will have the same characteristics as the ignitor fuel oil pumps. No. 2 fuel oil is more commonly used for ignitor systems and will be assumed herein. The pumps will be able to pump oil with a viscosity of 200 Saybolt

Seconds Universal (SSU) against the design discharge pressure at the design capacity. Fuel oil viscosity will be expected to vary between 33 and

200 SSU. Pump motors will be totally enclosed and explosionproof.

b. Types. Unlike a centrifugal pump, a rotary screw pump is a positive displacement pump, that will displace its capacity to the point of failure regardless of the resisting pressure. A fuel oil recirculation system will be designed to allow the pump to recirculate the fuel oil as the ignitor fuel

a. Application. A carbon dioxide system in a boiler plant is most commonly used to extinguish used to extinguish electrical hazards, such as transformers, oil switches and circuit breakers, and reducing the concentration of oxygen and the gaseous phase of the fuel in the air to the point where combustion stops.

automatic, manual or automatic-manual. Fires or conditions likely to produce fires may be detected by visual (human senses) or by automatic means. In the case of coal bunkers, methane detectors can be pipes through a pressure regulated system to discharge nozzles at the area of combustion. The sufficient for the largest single hazard protected or oil is modulated according to demand. In a fuel oil group of hazards to be protected simultaneously.

loading system the fuel oil is not modulated and a recirculation system is not necessary. In sizing the fuel oil pump, the pressure to overcome will be calculated from piping losses and elevation change to get the required pump discharge pressure. The accordance with NFPA 12 of the National Fire

Codes.

7-19.

Chemical feed pumps.

ignitor fuel oil pump capacity is determined from maximum fuel oil demand plus 20 percent for pump wear and safety factor.

a. Application. Chemical feed pumps are small capacity pumps used to inject chemicals into the condensate, feedwater and steam system at a controlled rate. Most chemical feed pumps are specified and purchased as a chemical feed unit that

7-17.

Nitrogen system.

a. Application. The nitrogen system is used to purge the boiler for protection from corrosion between hydrostatic test and initial operation and after chemical cleaning periods and outages.

b. Design. The boiler steam parts are filled with treated water until overflowing and then capped off with 5 psig of nitrogen according to the recomincludes a pump, tank, mixer and piping. Typical chemical systems used in a boiler plant are hydrazine, morpholine, phosphate and a metal surface passivating agent.

b. Design. The pump selection will have the capacity and discharge head to inject the chemical into the system. Pumps are rated by capacity in

7-15

7-16

TM 5-810-15

gallons per hour (gph), discharge head in psig and piston strokes per minute. The chemical feed pumps will be positive displacement metering type.

The pumps will have hydraulically balanced diaphragms, mechanically actuated air venting; all rotating parts to run in an oil bath with roller bearings; double ball check valves with Teflon 0ring seats on both suction and discharge. The pumps will have micrometer capacity adjustment from 0—100 percent while the pump is running and to have metering accuracy within plus or minus 1 percent.

c. Chemical feed unit. Chemical feed tanks for the mentioned chemicals will be 16 gage type 304 stainless steel with agitator, gage glass and low level alarm system. Piping will be stainless steel and valves will have Teflon seats. The chemical feed system will include a back pressure valve to insure accurate and consistent metering at all flows and will include a safety valve.

7-20.

Laboratory.

a. General. A laboratory is needed in every boiler plate to assist in analyzing chemical treatment and in early detection of problems. Samples of water and steam are taken from various systems and parts of systems to evaluate the system

*s condition.

b. Sample coolers. Sample coolers are required to condense steam and cool water to be handled.

Sample coolers are heat exchangers that will be sized to maintain the temperature at 77 degrees F.

Coolers for individual samples are either doubletube helical coils with cooling water counterflow cooling or submerged helical coils properly baffled to effect counterflow cooling. If a coil type of exchanger or a coil and condenser type of exchanger are used, they will meet the intention of

ASTM D 1192. If a multicircuit heat exchanger is used, it will meet the requirements of Section VIII,

ASME Boiler and Pressure Vessel Code.

7-21.

Sump pumps.

a. Application. Sump pumps are required in several applications at a boiler plant. Sump pumps primarily are used for storm water removal but also are used for ash hopper water overflow or any condition requiring removal of water from a sump.

b. Design. The pump will be sized for one and one-half times the maximum amount of expected drain rate. Two 100 percent capacity pumps will be used to supply full backup if overflow is dangerous.

The suction line between the suction vessel and the pump must be properly designed to prevent air pockets and cavitation. Sufficient NPSH must be available at the pump suction flange.

c. Construction. The pumps will be motor driven, vertical shaft configuration with bottom suction and open impeller. The pump will include a flanged column, discharge pipe flanged over soleplate, bearing lubrication piping and connections on the soleplate to support the pump and motor.

CANCELLED

TM 5-810-15

CHAPTER 8

PIPING SYSTEMS

8-1. General.

This chapter addresses the criteria for the steam plant piping systems. The design of the steam plant piping will be in accordance with the ASME B31.1.

diagram is shown in figure 8-3.

d. Fuel gas. The fuel gas system reduces gas pressure from the supplier

*s pipeline, totalizes flow to the plant, removes impurities from the gas, allows manual isolation of the plant from the

Gas piping will be in accordance with ASME

B31.8. Reference table 8-1 for piping system supply, provides visual indication of plant gas pressure, and electrically isolates the plant piping design notes.

from the buried supply piping.

e. Fuel oil. The fuel oil system includes pumps to

8-2. System descriptions.

move oil from outdoor storage tanks to the plant

a. Main steam. The main steam system delivers header. The functions performed by the fuel oil steam from the boiler outlet connections to the system are similar to those listed for the gas process. The main steam system consists of: piping system. Since oil is stored on site and since there is from each boiler outlet connection, superheating recirculation back to the fuel oil storage tank, more equipment (superheated boilers only), a common than one totalizing flow meter is needed to main steam line headered to the individual boiler calculate the amount of oil burned.

outlets, and piping which transports the steam to

f. Blowdown heat recovery. The blowdown heat the process. On superheated steam units the superrecovery system recovers part of the heat available heating equipment, which is an integral part of the in boiler blowdown water and discharges the unusboiler, consists of a primary superheater section, a able high-solids content water. The blowdown heat desuperheater, and a secondary superheater. The recovery system consists of: blowdown regulation system diagram is shown in figure 8-1.

equipment, a flash tank, a blowdown recovery heat

b. Low pressure steam. The low pressure steam exchanger, and interconnecting piping. The system system provides steam for use within the steam diagram is shown in figure 8-4.

plant. These uses include deaerator (DA) pegging

g. Instrument air. The instrument air system steam, sootblowing steam, steam coil air preheasupplies air to the pneumatic instruments and ters, boiler feed pump turbine drives, and feedcontrol devices throughout the plant. The instruwater heaters. The low pressure steam system ment air system consists of: instrument air comconsists of: steam pressure reducing station, DA, pressors, aftercoolers, air drying equipment, insootblowers, steam coils, turbine drives, feedwater strument air receiver, baghouse air receiver (when heaters, and interconnecting piping. The system required), and interconnecting and distribution diagram is shown in figure 8-2.

piping. The system diagram is shown in figure 8-5.

c. Feedwater. The feedwater system collects re-

h. Plant air. The plant air system supplies air for turning process condensate, treats raw water for makeup to the boiler, collects returning condensate from in-plant processes, conditions the condensate and makeup to remove corrosive gases, heats the

CANCELLED equipment to condition raw water for makeup to the boiler, a treated water and condensate storage tank, treated water and condensate pumps to pneumatic tools, maintenance uses, and other uses throughout the plant. Plant air may also be used for sootblowing and igniter atomizing purposes when required. The plant air system consists of: plant air compressors, aftercoolers, oil separating equipment on crosstie to instrument air system, plant air receiver, sootblower air receiver (when required), atomizing air regulating station (when required), and interconnecting piping. The system diagram is deliver water to the DA, a blowdown recovery heat shown in figure 8-6.

exchanger, a DA to remove the entrained corrosive

i. Boiler vents and drains. Boiler vents and gases from the water, boiler feed pumps to increase drains provide the means by which the boiler is the pressure of the water and deliver it to the vented and drained during startup and maintenance boiler, feedwater heaters to heat the water and operations. The system consists of piping from the protect the boiler economizer against acid condenvent and drain connections on the boiler to the sation of the flue gas at low loads, flow regulating appropriate disposal points.

stations, and interconnecting piping. The system

8-1

8-2

TM 5-810-15

Table 8-1. Piping Design Notes,

System

Main steam

(Saturated)

Origin

Boiler outlet

Termination

Process

Typical Design

Press. & Temp.

400 psig

450 degrees F

Main steam

(superheated)

Auxiliary

(low pressure) steam

Boiler outlet

Pressure reducing station

Process 400 psig

750 degrees F

Design Notes

Slope pipe ¼” per 100 ft. Thermal expansion compensation required. Traps and drains required. Insulate for thermal efficiency.

Slope pipe ¼" per 100 ft. Thermal expansion compensation required. Traps and drains required. Insulate for thermal efficiency.

Slope pipe ¼” per 100 ft. Thermal expansion compensation required. Traps and drains required. Insulate for thermal efficiency.

Steam coil steam supply

Auxiliary steam header

Deaerator. feed150 psig water heaters steam coils BFP

375 degrees F turbine sootblowers

Steam coil inlet 150 psig

375 degrees F

Building heat Auxiliary steam Building heating 150 psig system (reducing equipment 375 degrees F station)

Boiler feed pump Boiler feed pump Boiler economizer 450 psig discharge 230 degrees F

Boiler feed pump Deaerator storsuction age tank

Boiler feed pump 5 psig

225 degrees F

Boiler feed pump Boiler feed pump Deaerator recirculation discharge

450 psig

230 degrees F

Main steam desuBoiler feed pump Main steam desu450 psig perheater discharge perheater 230 degrees F

Sootblower steam Auxiliary steam system (reducing station)

Sootblowers 150 psig

375 degrees F

Boiler continuous Boiler drum blowdown

Instrument air

Plant air

Instrument air compressors

Plant air compressors

Flash tank

Instrument sir piping system

Plant air piping system

400 psig

450 degrees F

100 psig

100 degrees F

100 psig

100 degrees F

Slope pipe ¼” per 100 ft. Thermal expansion compensation required. Insulate for thermal efficiency. Traps and drains required.

Slope pipe ¼” per 100 ft. Thermal expansion compensation required. Traps and drains required. Insulate for thermal efficiency.

Check valve required on each pump. Insulate for thermal efficiency.

Strainer required on each pump. Insulate for thermal efficiency.

Breakdown orifice required for each pump. Insulate for thermal efficiency.

Insulate for thermal efficiency.

Slope pipe ¼” per 100 ft. Thermal expansion compensation required. Traps and drains required. Insulate for thermal efficiency.

Compensation for thermal expansion and boiler movement required. Insulate for thermal efficiency.

No insulation required.

No insulation required.

Atomizing air Plant air system Ignitors No insulation required.

Boiler drains and Boiler drum mud Atmosphere, 400 psig Compensation for boiler movement required. Insulate lets vents

Steam coil drain

& vent

Deaerator vents drum, waterwall drain headers

Deaerator

Safety valve vents Safety valve outAtmosphere

450 degrees F

Steam coil outlet Deaerator (drain) 10 psig atmosphere (vent) 240 degrees F

220 degrees F

As required bends or turns.

for burn protection.

Insulate for thermal efficiency.

CANCELLED

Atmosphere 5 psig Insulate for burn protection.

Use drip pan elbows on steam safety valves. Avoid

Condensate makeup pump discharge

Condensate makeup pump

Deaerator

100 psig

100 degrees F

10 psig

100 degrees F

Check valve required on each pump. Insulate for thermal efficiency.

Condensate makeup pump suction

Condensate storCondensate age tank makeup pump

5 psig

100 degrees F

Strainer required on each pump. Insulate for thermal efficiency.

TM 5-810-15

Table 8-1. Piping Design Notes. (Continued)

Typical Design

System

Condensate makeup pump recirculation

Treated water

Origin

Condensate makeup pump discharge

Termination Press. & Temp.

Condensate stor10 psig age tank 100 degrees

Condensate return

Potable water

Service water

Trap return

Fire protection

Floor and roof drains

Sanitary drains

Ash sluice water

Bottom ash water Bottom ash hopper

Nitrogen

Coal bunker & pulverizer inerting gas

Ignitor fuel

Water treatment Condensate stor10 psig system age tank 60 degrees F

Process

Water main

Condensate storAs required age tank

Restrooms, lock50 psig ers, drinking 60 degrees F fountains, etc.

Water main

Steam traps

Water main or service water

Drain hubs

Restrooms, lockers, drinking fountains, etc.

Ash pond

Air compressors, 50 psig aftercoolers 60 degrees F

Waste or drain 150 psig

375 degrees F

Sprinklers and hose stations

150 psig

60 degrees F

Within 15 feet 50 psig outside building 60 degrees F

Drainage 100 psig

60 degrees F

Nitrogen bottle manifold

Gas bottle manifold

Fuel oil storage tank

Bottom ash hop60 degrees F per

Ash handling equipment

150 psig

100 degrees F

Boiler drums

Coal bunkers & pulverizers

150 psig

60 degrees F

150 psig

60 degrees F

Ignitors As required

Chemical feed

Samples

Fly ash

Design Notes

Breakdown orifice required for each pump.

No insulation required.

Insulate for thermal efficiency.

Piping must be sanitized before use. No insulation required.

No insulation required.

Insulate for burn protection.

No insulation required. All valves OS&Y type FM approved.

Slope pipe ¼” per 100 ft. Provide cleanouts, use lateral fittings, avoid sharp turns. Coat where buried.

Slope pipe ¼” per 100 ft. Provide cleanouts, use lateral fittings, avoid sharp turns.

No insulation required.

No insulation required.

No insulation required.

No insulation required.

No insulation required.

Chemical feed pumps

Strainers on pump suction and check valves on pump discharge required. No insulation required.

Boiler drum, de450 psig aerator (boiler drum)

10 psig

(deaerator)

Boiler drum, deaerator feedwater

Water analysis equipment

60 degrees F

400 psig

(boiler drum main steam)

450 psig FW

Sample coolers required on boiler drum.

CANCELLED

450 degrees F boiler drum

230 degrees F

DA FW

Fly ash hoppers Ash handling As required Insulate where cooler climates may develop condensation in pipe.

8-3

TM 5-810-15

8-4

j. Deaerator vent. The DA vent piping provides piping must be designed to pass the required flow the means by which the entrained gases removed by the DA are vented to the atmosphere. The system will contain an orifice sized for the venting requirements determined from operating conditions without adversely effecting safety valve operation.

l. Miscellaneous water systems. Miscellaneous water systems include service and potable water

CANCELLED and DA design.

k. Safety valve vents. Safety valve vent piping provides for the safe discharge of fluids from safety system will provide water for the various cooling requirements in the plant, such as air compressor intercoolers and aftercoolers, and will provide valves. Water safety valves require piping from the safety valve outlet to drain. Air and gas safety valves require piping from the safety valve outlet to atmosphere or to a safe location. Steam safety valves require piping from the safety valve outlet to a safe location that is outside the building. Steam safety valve vents also require provisions for removal of water condensed under the safety valve seat and in the vent piping itself. Safety valve water for personnel usages. The ash sluice water system is required when a hydraulic bottom ash system is used. Ash sluice water provides the water for ash jet pumps and bottom ash hopper filling and sealing water requirements.

m.

Miscellaneous gas systems. Miscellaneous gas systems include nitrogen system and coal bunker and pulverizer inerting systems. The nitrogen system is used to fill any of the boilers

TM 5-810-15

with nitrogen when it is to be out of service for an extended period. The system consists of nitrogen bottles, manifold, and interconnecting piping. The coal bunker and pulverizer inerting system is used to fill coal bunkers and pulverizers with an inert gas, usually 002 when fires are detected in the equipment or when the equipment is to be out of steel piping or tubing for interconnection of system components and the DA storage tank.

p. Samples. The samples system collects samples from various points in the plant for use in determining chemical feed requirements based on water quality. Sample points will include boiler drum, feedwater, and condensate. The system coning.

service for an extended period. The system consists of gas bottles, manifold, and interconnecting pip-

n. Ignitor fuel. The ignitor fuel system provides fuel for burner ignitors. Ignitors are used on gas, sists of sample coolers (boiler drum) and tubing from the sample point to a central location when desired.

8-3. Valves.

oil, pulverized coal, and ACFB boilers. The ignition fuel may be oil, natural gas or liquified petroleum gas based on the type of ignitors used. The system

a. General. All valves installed in piping systems must be suitable for the pressure and temperature of the piping system in which they are installed.

consists of pressure regulating stations and

Valves will be selected based on type of service interconnecting piping.

(throttling or isolation), type of process fluid

o. Chemical feed. The chemical feed system sup-

(water, steam, air), and special conditions plies chemicals to the feedwater system at the DA

(corrosive or abrasive process). Consideration must storage tank to maintain water quality. The system be given to materials of construction and packing consists of chemical feed tanks for mixing and materials. Table 8-2 summarizes the types of valves storage of chemical solutions; positive displacement and their application.

metering type chemical feed pumps; and stainless

8-5

TM 5-810-15

8-6

CANCELLED

TM 5-810-15

CANCELLED

8-7

TM 5-810-15

8-8

CANCELLED

TM 5-810-15

Valve Type

Globe

Gate

Butterfly

Plug

Ball

Check

Diaphragm

Pinch

Needle

Relief or safety

Table 8-2. Valve Types.

Application

Throttling and flow regulation service, control valves

Fluid

Steam, water, air gas, oil

Isolating nonthrottling service Steam, water, air, gas suitable for high temperature ing

Isolating service, intermittent throttling, limited control valve application

Isolating service, intermittent throttling and pressure

Low pressure and temperature water and other fluids

CANCELLED

Isolating service, intermittent throttling

Allows flow in one direction only, pump discharge pip-

Water, air, gas—low pressure applications

Steam, water, air, gas, oil

Provide flow control and leaktight closure Corrosive, abrasive and solids in suspension

Low pressure and temperature, noncorrosive fluids Isolating service for large amounts of solids in suspension

Volume control valve used in small instrument, gage and meter lines

Prevents excessive overpressure in process and piping

Water, air, gas

Steam, water, air, gas system

8-9

TM 5-810-15

b. Valve types. Numerous types of valves are available including globe, gate, butterfly, plug, ball and check valves. Valves can be furnished with flanged, butt welded, socket welded, or screwed end connections.

c. Valve construction. Valves must be constructed of suitable materials for the pressures, temperatures, and fluids for which they will be used. Table 8-3 summarizes body and packing materials and their application. Consideration will be given to special disc and seat materials and valve bonnet types when required by special process conditions.

8-4. Pipe insulation.

a. Acceptable types. Table 8-4 shows the acceptable types of insulation material.

b. Applications.

(1) Burn protection. Where applicable, insulation will be sufficiently thick to provide burn protection as required by OSHA regulations.

Body Material:

Cast Iron

Steel

Stainless

Steel

Bronze

Table 8-3. Valve Construction.

Application

Pressure up to 250 psi, temperature up to 267 degrees F, water, oil, gas

Pressure up to 9000 psi, temperature up to

800 degrees F, water, oil, gas, steam

Pressure up to 9000 psi, temperature up to

1200 degrees F, corrosive fluids

Pressure up to 300 psi, temperature up to 400 degrees F, water, air gas

Packing

Material:

Teflon

Graphite

Temperature up to 450 degrees F, water, oil, gas

Temperature up to 1000 degrees F, water, oil, gas, steam

8-10

Table 8-4. Acceptable Insulation Types.

Insulation Type

Asbestos free calcium silicate ASTM C

533 and expanded silica (perlite)

Advantages

Inexpensive, easy to handle, numerous manufacturers, for use from 100 degrees F to 1500 degrees F.

Disadvantages

Deteriorates in moist conditions, not very compressible, unsuitable for direct buried applications.

Fiberglass ASTM E-84 Inexpensive, easy to handle, numerous manufacturers, for use from -40 degrees F to 1200 degrees F.

Loses insulating value in moist conditions, unsuitable for direct buried applications.

Cellular Glass Impervious to moisture, easy to handle, for use from -40 degrees F to 1200 degrees F can be used above and below ground.

Not compressible, few manufacturers.

*Insulation systems using composite of two or more acceptable insulations may also be acceptable.

(2) Thermal efficiency. For purposes of efficiency, the recommended economic thickness of pipe insulation is shown in table 8-5. Further thicknesses of insulation will be installed on the basis of a LOCA.

CANCELLED

Nominal Pipe size, in.

Temperature of pipe F

100-199 200-299 300-399 400-499 500-599 600-699 700-799 800-899 900-999 1000-1099 1100-1200

UTILITY—STEAM GENERATION l½ and less

2

3

4

5

6

1

1

1

1

1

1

1

1

1

1

1

1

1

1

1

2

2

2

2

2

2

2

2

2

2

2

2

2

3

3

3

3

3

2

2

3

3

3

3

3

3

3

3

4

4

4

4

4

4

3

3

TM 5-810-15

Table 8-5. Recommended Economic Thickness for Pipe Insulation. (Continued)

Temperature of pipe F

Nominal Pipe size, in.

7

8

9

10

11

12 l4 and up

100-199 200-299 300-399 400-499 500-599 600-699 700-799 800-899 900-999 1000-1099 1100-1200

UTILITY—STEAM GENERATION

2

2

2

2

3

4

4

4

4

2

2

2

2

2

3

3

3

3

3

3

3

3

3

4

4

4

4

4

4

4

4

4

4

4

5

5

5

5

5

8-5. Pipe hangers, anchors and supports.

a. Design. Hangers, anchors and pipe supports will be designed to meet ASME B31.1 requirements where applicable. Pipe hangers will be in accordance with MSS SP-69.

b. Spacing. Guidelines for pipe support spacing and carrying capacities are provided in ASME

B31.1

Fluid

Steam

Table 8-6. Piping Velocity Guidelines.

Application

Superheated steam, boiler leads

Auxiliary steam, exhaust lines

Velocity

150-333 fps

100-250 fps

Saturated and low pressure steam 100-167 fps

Water Centrifugal pump suction lines 3-5 fps

8-6. Pipe expansion compensation.

Feedwater 8-15 fps

a. Design. The thermally induced expansion of piping materials can be compensated for with normal pipe bends and the proper placement of anchors. The thermal expansion of common piping materials is shown in Appendix B of the ASME

B31.1.

b. Expansion devices. When piping system design is unable to compensate for pipe expansion, expansion bends or expansion joints will be used.

Expansion joints and bends will conform to ASME standards.

General service

Potable water

4-10 fps

Up to 7 fps without exceeding maximum allowable velocities or causing excessive pressure drops.

e. Sizing calculations. Empirical equations and charts have been devised to calculate pressure drops with reasonable accuracy. The Darcy Equation has been shown to produce accurate results.

8-8. Steam traps.

a. Application. Steam traps are devices that are

8-7. Pipe sizing.

used to accomplish the following functions:

a. General. Selection of the proper pipe size for

(1) Allow condensate resulting from loss of any particular application is dependent upon nulatent heat in steam to flow from the steam system merous variables. Pipe sizing is based on velocity, pressure loss, and friction loss calculations.

b. Data requirements. In order to properly size piping, pertinent data must be organized for use in

CANCELLED material (friction factor), process fluid, flow requirements, design pressures and temperatures, allowable pressure drop, velocity requirements, and to a lower pressure system or to atmosphere.

(2) Vent air and other gases from the steam system to maintain steam temperature and reduce corrosion.

(3) Prevent escape of steam from the steam system.

b. Selection. The factors to be considered when selecting the proper steam trap include condensate preliminary piping layout.

load, continuous or intermittent operation, system

c. Velocity guidelines. General guidelines for pressure, constant or variable pressure and load, allowable velocities in piping systems are shown in table 8-6.

d. Pipe sizing philosophy. Piping will be sized to obtain a maximum velocity that corresponds to the allowable pressure drop for the system. It is indoor or outdoor installation, failure mode (open or closed), air and noncondensible gas venting, and resistance to water hammer.

c. Design. Trap selection and sizing depends on many factors. The condensate load on a trap involves range of load as well as rate of change.

Nearly all traps service a long range. A trap will be desirable to keep velocities as high as possible

8-11

TM 5-810-15

sized for the maximum expected condensate load and a safety factor. Oversizing a trap can increase losses, both for good traps as well as traps that fail open. It is recommended that a safety factor of 2:1 be used to size a trap in a constant pressure usage and safety factor of 3:1 be used if the pressure varies. The major steam loss from a trap is at a failed-open condition and can cost thousands of dollars a year if not detected. However, a failed close trap may cause extensive damage because of corrosion or water hammer from condensate that is not discharged. Selection of the failure mode depends on the design conditions and maintenance practices. All traps are subject to freezing, particularly due to condensate flow blockage. Of all types of traps, float traps are most subject to float to open the trap until it is drained and the float loses buoyancy. A float trap does not have to be primed as an inverted bucket trap does. However, buildup of solids and sludge in the trap body can prevent the float from sinking and closing the valve. The discharge from the float trap is generally continuous. This type is used for draining condensate from steam headers, steam heating coils, and other similar equipment. When a float trap is used for draining a low pressure steam system, it will be equipped with a thermostatic air vent.

(3) Thermostatic. The thermostatic trap opens and closes by means of a force developed by a temperature sensitive actuator. A basic problem for all thermostatic traps is keeping the actuating temperature close to the saturation temperature so the condensate will be hot, but not allow live steam to blow out the trap. If the actuating temperature is not close to the saturation temperature, there is a freezing. Steel bodied traps resist freezing better than iron. Trap cost is an important consideration as initial expense may not justify selection because of maintenance characteristics and life span. The inverted bucket type of trap has the longest life, followed by the float trap, thermostatic trap and the thermodynamic trap consecutively for long life.

d. Types. There are four basic types of steam traps: inverted bucket, float, thermostatic and thermodynamic.

(1) Inverted bucket. This type of steam trap is the most widely used. When properly sized, steam water, and also, that the condensate may back up to an unacceptable level. The discharge from this type of trap is intermittent. Thermostatic traps are used to drain condensate from steam heating coils, unit heaters and other similar equipment. Strainers are normally installed on the inlet side of the steam trap to prevent dirt and pipe scale from entering the loss is kept to a minimum. The inverted bucket trap contains an inverted bucket inside the trap body.

The inverted bucket is fastened to a linkage in such a manner that it will close the trap outlet when steam enters from beneath the bucket. As the steam cools and condenses (assisted by a bucket vent), the bucket loses its buoyancy and the trap opens releasing the condensate. Gases mixed with the trap. The thermostatic trap is the most common of all trap types used for two pipe steam heating systems. When this type of trap is used for a heating system, at least 2 feet of pipe will be provided ahead of the trap to cool the condensate. This permits condensate to cool in the pipe rather than in the coil, and thus maintains maximum coil efficiency. Thermostatic traps are recommended for steam pass through the inverted bucket trap partly by way of the bucket vent and partly in any steam low pressure systems up to a maximum of 15 psi.

When used in medium or high pressure systems, discharged by the trap. The discharge from the inverted bucket trap is intermittent and requires a differential pressure between the inlet and discharge of the trap to lift the condensate from the bottom of the trap to the discharge connection. They are they must be selected for the specific design temperature. In addition, the system must be operated continuously at that design temperature.

namic disc traps are used for intermittent service, resistant to water hammer, operate well at low loads, and fail open. Bucket traps may be subject to damage from freezing and have only fair ability to handle start-up air loads. Inverted bucket traps are where they operate well under variable pressure conditions, are resistant to damage from freezing and water hammer, and fail open. A disadvantage of the thermodynamic trap or disc trap is poor gas well suited for draining condensate from steam lines or equipment where an abnormal amount of air is to be discharged and where dirt may drain into the trap.

(2) Float. A float trap has a small chamber containing a float and linkage that multiplies the float

*s buoyancy. The condensate will cause the handling. The pressure drop when air or 002 are flowing in the trap resembles that of steam, so that large amounts of air will close the trap. Therefore, another air removal method is necessary for startup of a steam system. Thermodynamic disc traps will not be used where high back pressures, or low load conditions might occur. They are best suited for

8-12

use on high pressure superheated steam mains and steam tracer lines.

8-9. Piping accessories.

a. Strainers. Strainers are a filtering device used to remove solids from liquid piping systems and to protect equipment. Strainers are normally placed in the line at the inlet to pumps, control valves or other types of equipment that are to be protected against damage.

(1) Y-type strainers. Y-type strainers are used in small piping for protection of in-line devices such as steam traps. Y-type strainers may also be used in pump suction lines on small pumps such as chemical feed pumps. Y-type strainers utilize a screen mesh to remove solids and will have a blowoff valve and a means for removing the screen for cleaning.

(2) T-type strainers. T-type strainers are used in large piping on pump suction lines to protect the pump. T-type strainers will utilize a perforated basket to remove solids and will have inlet and outlet pressure gauges or a differential pressure gauge to indicate when the basket requires cleaning. Strainers for pump protection should be not

TM 5-810-15

less than 40 mesh. Screen material will be suitable for liquid or gas in line. Strainer body will be equal to material specified for the valves in the same service.

(3) Duplex strainers. Duplex strainers are used on low pressure systems and contain two sections which can be individually cleaned while the process is in operation. One section is operable while the other section is isolated. Duplex strainers will have inlet and outlet pressure gauges or a differential pressure gauge to indicate when a basket requires cleaning.

b. Safety valves. Safety valves must be provided in accordance with the ASME Boiler and Pressure

Vessel Code. Safety valves are pre-set to open fully at a certain pressure and to pass a certain flow capacity. The pressures and capacities are determined from code requirements. Safety valves on the boiler proper are normally provided by the boiler manufacturer. Other equipment requiring safety valves includes the DA, feedwater heater shell, feedwater heater channel, and air receivers.

Pressures and capacities for this equipment is also determined from code requirements.

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TM 5-810-15

CHAPTER 9

INSTRUMENTS AND CONTROLS

9-1. General.

quirements, system security requirements, and

LCCA.

This chapter addresses the criteria for the selection

(3) Distributed control systems include the of instruments and controls to meet the process input output sensors and actuators which requirements of the steam plant.

are connected to the termination units which

a. Pneumatic controls. Most control system condition and multiplex the signals for communimanufacturers have discontinued production of cation to the microprocessor unit controllers where pneumatic controls systems. Replacement parts and the logic resides for control of the process variable.

qualified service for the equipment are difficult to

All microprocessor unit controllers communicate procure. For these reasons pneumatic controls with each other and to a data highway which should not be used for new installation.

includes nodes for the operator interface station,

b. Electronic controls. Electronic systems have engineering work station, and programmable logic been made obsolete by the microprocessor based controllers for balance of plant controls.

control systems. Manufacturers no longer make

(4) The distributed control system logic for the electronic control systems and they should not be controls and the 110 for the process are located in specified for new installations.

the vicinity of the process. This process controller

c. Microprocessor based controls. Microprowill communicate with other process controllers, cessor based control systems can provide sequential engineers work station, data acquisition system and logic control and modulating control in one control the operator interface. The control system will be device. This capability makes available boiler conconfigured to allow the process controller to trol systems, which use both sequential logic and continue to function upon loss of communication modulating control, that are more flexible and with the operator interface, data acquisition system reliable as well as more cost effective. Processing and other process controllers.

units can be utilized as single loop controllers or

d. Control system reliability. The methods used more powerful processing units can be applied to to ensure control system reliability will be based on individual control subsystems, such as combustion unit size, importance to plant operation, and the control of ash handling control.

(1) Inputs from and outputs to field devices may be multiplexed. Data highways connect all processing units to data storage and acquisition components, cathode ray tube (CRT) displays and operator consoles, loggers, and printers, providing communication among all components. Communications between modulating control devices and sequential logic flow freely and are not subject to the restrictions inherent with analog and mechanical relay electronic systems which require hard-wiring between components. Data acquisition and using CRT

CANCELLED control stations indicators and recorders mounted on an operator console. When CRT

*s, keyboards and printers are utilized redundant microprocessors are sometimes utilized depending on unit size.

service must be detected and alarmed. Loss of either supply alone must not affect operation of the controls. Distributed control systems will include power supplies which are redundant or backed up so that loss of any power supply will not cause loss of power to the control logic. Loss of power supply should be alarmed.

(2) Control system safeguards.

Microprocessor based controls are highly reliable but safeguards must be provided to limit the effects

(2) Program logic can be changed or expanded the primary power source or the backup power of component failure. Microprocessor based readily with limited hardware revisions. System uninterruptable power supply (UPS). Loss of either control systems require grounding to a ground mat selection can range from programmable controller either from a separate ac source or an with an impedance of three ohms or less for systems to fully distributed digital control systems.

based systems must have a backup power supply protection of system components to reduce forced

The criteria for selection of the proper system must have a backup supply. Microprocessor plant outages. Spare circuit cards for critical microprocessor based system will include unit size,

(1) Power sources. Power to the control components are to be available at the boiler plant, the amount and type of modulating control and backup hardware.

as well as spare microprocessing units that can be sequential logic required, operator interface recost of control system failure versus the cost of

9-1

9-2

TM 5-810-15

writing specifications. Data rates of approximately

1 mega baud are available.

substituted for faulty units which are encountered during start-up and operation of the plant. For critical subsystems consideration should be given to redundant microprocessors with automatic switching of inputs and outputs from one microprocessor to another. The data highway should be looped or redundant so that failure of a segment of the data highway will not result in the loss of communications. Control elements should be designed to fail in a safe condition upon loss of the electric or pneumatic power to the actuators or input signal. The loss of power at the component or subsystem levels must cause the associated auto/manual stations to switch to the manual mode of operation. The control logic should have continuous self diagnostic capability and, upon detection of component failure, transfer to manual and indicate the cause of the failure.

Microprocessors are to contain nonvolatile memory which will not be erased on power failure.

e. Control system expansion. The control system architecture should allow expansion at all levels of the system. The 110 can be expanded by installing additional cards or racks with signal conditioning for communication to the control system processing units. Additional nodes can be added to the data highway to allow additional processing units, engineering work stations, and operator interface

CRT

*s to be added to the control system.

f. Data link. The process 110 signals are connected to the termination units and through signal conditioners to the microprocessor controllers. The control system data highway for exchange of data between microprocessor based controllers and between microprocessor based controllers, data acquisition systems, operator interface and engineering work stations will be redundant. The data highways will utilize coax, twines of fiber optic cabling. The speed of data transmission is increasing and should be investigated prior to

9-2. Combustion controls.

a. General. The purpose of combustion control systems is to modulate the quantity of fuel and combustion air inputs to the boiler in response to a load index or demand (steam pressure or steam flow) and to maintain the proper fuel/air ratio for safe and efficient combustion for the boiler

*s entire load range.

b. System types. Three types of combustion control systems are available: series, parallel, and series-parallel. Each of these types are schematically represented in figure 9-1.

(1) Series control. A series control system as shown in figure 9-1(a) uses variation in the steam header pressure (or any other master demand signal) from the setpoint to cause a change in the combustion air flow which, in turn, results in a sequential change in fuel flow. The use of series control is limited to boilers of less than 100,000 pph that have a relatively constant steam load and a fuel with a constant Btu value.

(2) Parallel control. A parallel control system as shown in figure 9-1(b) uses a variation from setpoint of the master demand signal (normally steam pressure) to simultaneously adjust both the fuel and combustion air flows in parallel. This type of system is applicable to stoker-fired boilers, pulverized coal fired boilers, gas/oil fired boilers and atmospheric circulating fluidized bed (ACFB) boilers.

(3) Series-parallel control. A series-parallel control system as shown in figure 9-1(c) should be used to maintain the proper fuel/air ratio if the Btu value of the fuel varies by 20 percent or more, if the Btu input rate of the fuel is not easily monitored, or if both of these conditions are present. These conditions normally exist on pulver-

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ized coal fired and ACFB boilers. Variations in the steam pressure setpoint adjust the fuel flow input.

Since steam flow is directly related to heat release of the fuel, and because a relationship can be established between heat release and combustion air requirements, steam flow can be used as an index of required combustion air. Note however that this relationship is true only at steady load conditions.

c. System categories. Combustion controls can be further divided into two categories within the basic types: positioning control and metering control, as shown in figure 9-2.

(1) Positioning control. Positioning systems require that the final control elements move to a preset position in response to steam pressure variations from a setpoint. Series positioning control will not be covered here since it is only used on very small boilers operating at constant loads.

Parallel positioning systems that use a mechanical jackshaft to simultaneously position fuel feed and air flow from a single actuator apply to packaged type gas/oil fired boilers in the 20,000 to 70,000 pph size and is shown in figure 9-2a. This system

TM 5-810-15

allows the operator to load the boiler over its complete operating range. The fuel valves and air damper are operated by the same drive through a mechanical linkage. The gas and oil valves include cams which are adjusted at start up to maintain proper fuel air ratio over the operating range of the boiler. Parallel positioning systems with fuel/air ratio control as shown in figure 9-2(b) are suitable for use on gas/oil and stoker fired units. This system allows the operator to adjust the fuel/air ratio for the entire load range of the boiler. The addition of steam flow correction of air flow to parallel positioning with fuel/air ratio control creates a system suitable for use on ACFB, gas/oil and pulverized coal fired units as shown in figure 9-

2(c). This system uses variation of steam pressure from a setpoint to initially control fuel and air inputs. The system recorrects combustion air flow using steam flow as a setpoint for air flow, since steam flow is a function of fuel Btu input (inferred fuel flow). This system relates directly to a seriesparallel type control with the addition of a feedforward signal from the steam pressure controller to the combustion air control.

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9-3

TM 5-810-15

(2) Metering control. Metering control systems regulate combustion based on metered fuel and air flows as shown in figure 9-3. The master demand developed from steam pressure error establishes the setpoints for fuel and combustion air flows at the controllers. The controllers drive the final control elements to establish proper fuel and flows which are fed back to the controllers.

Maximum and minimum signal selectors are used to prevent the fuel input from exceeding available combustion air on a boiler load increase and to prevent combustion air from decreasing below fuel flow requirements on load reduction. This system is a cross-limiting flow tie back system with air leading fuel on load increase and fuel leading air on load reduction. This system is applicable to gas and oil, pulverized coal, and ACFB fired units.

d. System selection. Table 9-1 summarizes the combustion control systems discussed and their application to the various types of boilers.

e. Stoker system controls.

(1) Fuel flow control. The components of a stoker system must respond to the fuel flow demand signals generated by the combustion control system. For spreader stokers the coal feed to the overthrow rotor will vary with the demand signal.

Grate speed on traveling grate and traveling chain grate stokers will respond to the demand signal.

The frequency and duration of vibration cycles on vibrating grate stokers will vary with the demand signal. In all cases the relationship between fuel flow and unit load will be determined for use in the combustion control system to properly control fuel flow in response to the demand signal.

(2) Combustion air control. The combustion air flow is normally controlled at the FD fan. Two methods that are commonly used are control of inlet vanes on the FD fan or control of the FD fan inlet damper. If a metering control system is used the combustion air flow should be measured down

9-4

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TM 5-810-15

Control System Oil Stoker Coal (PC)

Jackshaft positioning

Series control X** X**

Parallel positioning

Parallel positioning with steam flow correction of air

Table 9-1. Combustion Control System Selection Guide.

Parallel metering with cross limiting and flow tie-back

Gas/

X*

X

X

X

X

X

X Recommended Application

Boiler Type

Multiple

Pulverized Burner

X

X

PC ACFB

X

*Restricted to use on boilers 70,000 pph and under.

**Restricted to use on boilers under 100,000 pph with constant

(2) Combustion air control. Combustion air flow in pulverized coal systems consists of primary air flow and secondary air flow. Primary air is the air which transports the pulverized coal to the burner or burners. Secondary air is the air delivered by the FD fan to the boiler to support combustion.

Total air flow is the sum of secondary air flow and all primary air flows. Secondary air is measured downstream of the FD fan and controlled by positioning FD fan inlet vanes or inlet damper.

Primary air can be supplied by the FD fan or by a primary air fan. Primary air is normally measured on each pulverizer.

(3) Combustion air flow measurement. Accurate combustion air flow measurement is essential for combustion control systems of pulverized coal fired boilers. Secondary air flow will be measured with a venturi section or air foil flow element in the ductwork between the FD fan and the boiler windbox. The flow element should be designed to provide a design differential pressure across the flow element of not less than 2-inches wg at full load conditions. Primary air flow will be measured on each pulverizer with a venturi section or pilot tube between the primary air fan and the pulverizer.

load and constant Btu value fuel.

The design pressure differential pressure across the stream from the fan outlet. The relationship beprimary air flow elements should not be less than 2tween inlet vane or damper position and air flow inches wg at full load. The transmitters selected for will be determined for use in the combustion primary air flow and secondary air flow will be control system or for characterizing the final condifferential pressure transmitters that are accurate trol element. Overfire air flow on stoker fired units in the range of differential pressure developed by normally is not measured. If overfire air is to be the flow elements.

controlled the air flow demand signal will be used to control overfire air in parallel with combustion air.

(3) Combustion air flow measurement. Accurate combustion air flow measurement is extremely important in combustion control systems for stoker fired boilers. A venturi section of air foil flow element should be provided in the ductwork between the FD fan and the stoker or a Piezometer ring may be installed at the FD fan inlet. The flow element will be designed to provide a design differential pressure across the flow element of not

CANCELLED flow transmitter selected for combustion air flow will be a differential pressure transmitter that is accurate in the range of differential pressure developed by the flow element.

that total air flow is low, an error signal from air flow control reduces the firing rate demand to the pulverizer master to restore the proper fuel/air ratio. Since coal flow to the burner is a function of primary air flow the primary air damper and coal feeder speed control receive the same demand signal. If an error develops between demand and measured primary air flow or coal feeder speed, the controllers adjust the primary air flow or feeder

f. Pulverized coal system controls.

controls. If an upset occurs in the fuel/air ratio such speed to eliminate the error. If primary air flow is

(1) Fuel flow control. Fuel flow in pulverized parallel to all pulverizers which have duplicate less than feeder speed demand, the feeder speed coal systems is established by coal feeder inputs to pulverizer master demand signal is applied in demand is made equal to the primary air flow by the pulverizer. Coal feeder speed controls the fuel develop the demand to the pulverizer master. The the low select auctioneer. A minimum pulverizer flow to the pulverizer. The volumetric rate of coal total fuel flow, which is the sum of all feeders to loading and a minimum primary air flow limit flow delivered to the pulverizer is directly related rangement the firing rate demand is compared to should be used to maintain the pulverizers above to feeder speed. Feeder speed varies with fuel flow multiple pulverizer control scheme. In this arthe minimum safe operating load to maintain demand.

(4) Pulverizer controls. Figure 9-4 shows one adequate burner nozzle velocities and to maintain

9-5

TM 5-810-15

for all pulverizer loads.

g. Gas/oil system controls.

(1) Fuel flow control. Fuel flow in gas/oil fired boilers is controlled by operation of gas or oil control valves in the supply lines to the burners.

The gas or oil control valves are modulated to control fuel flow based on the demand signal generated by the combustion control system. Gas flow to the burner is measured by taking the differential pressure across an orifice. Oil flow to the burners will be measured by a rotating disk type meter. Metering type control systems utilize the fuel flow and unit load in the combustion control

9-6

system to properly modulate fuel flow in response to the system demand.

(2) Combustion air control. The combustion air is normally controlled at the FD fan. Air flow for package boilers is normally controlled by outlet dampers at the FD fan. Other methods that are used include control of the FD fan inlet vanes or control of the FD fan inlet damper. The relationship between inlet vane or damper position and air flow will be determined for characterizing the final control element. When a metering type control system is used air flow is measured downstream of the FD fan or a piezometer may be installed at the

FD fan inlet.

(3) Combustion air flow measurement. Accurate combustion air flow measurement is also important in metering type combustion control systems for gas/oil fired boilers. A venturi section or air foil flow element should be provided in the ductwork between the FD fan and the burner windbox or a piezometering may be installed at the

FD fan inlet. The flow element will be designed to provide a design differential pressure across the flow element of not less than 2 inches wg at full load conditions. The flow transmitter selected for combustion air flow will be a differential pressure transmitter that is accurate in the range of differential pressure developed by the flow element.

(4) Oil atomization. The oil to the burner will be atomized utilizing steam or compressed air. A control valve installed in the atomizing steam or air line will be controlled to maintain the atomizing medium pressure above the oil supply pressure to the burner.

h. Atmospheric circulating fluidized bed (ACFB) boiler.

(1) Fuel flow control. Main fuel flow in an

ACFB system is established by fuel flow through the feeder to the combustor. The volumetric rate of fuel flow is directly related to feeder speed. The coal feed demand speed utilizes the lower of the total air flow or firing rate demand as the set point and compares the set point to total fuel flow

TM 5-810-15

to develop the demand signal for the feeder master.

The feeder master demand signal is applied to all feeders which have duplicate controls. Therefore, as firing rate demand is increased or decreased the feeder speed is increased or decreased. Coal chute air flow compares measured air flow to load flow to operate the coal chute air damper. A feed forward signal based on rate of change is also used to modulate the coal chute air control damper. Coal feeder and coal chute air damper control is shown in figure 9-5.

(2) Combustion air control. Combustion air flow in ACFB systems consists of primary air flow, overfire air flow, stripper cooler air flow, and main fuel chute air flow. Primary air is introduced below the bed and keeps the fuel and bed in suspension.

Overfire air is delivered by the FD fan and is utilized at loads above 50 percent to control furnace exit gas temperature. The stripper cooler air flow is utilized to cool the excess bed material which is removed in the stripper section. Main fuel chute air flow is utilized to sweep the fuel tube to the combustor. Total air flow is the sum of primary air, overfire air, stripper cooler air, and coal chute air flow. All air can be supplied by the FD fan or separate primary air and FD fans may be utilized.

The primary air, overfire air and stripper cooler are controlled by positioning the appropriate damper.

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9-7

9-8

TM 5-810-15

Air supply is maintained by modulating the FD fan and primary air fan inlet vanes or dampers to maintain pressure in the FD fan outlet duct.

(3) Combustion air flow measurement. Accurate combustion air flow measurement is also important in combustion control systems for ACFB boilers. Measurement of primary air flow, overfire air flow, stripper cooler air flow, and coal chute air flow will be measured with a venturi section or air flow element in the ductwork to the various equipment. The design pressure differential pressure across the air flow elements will be not less than 2-inches wg at full load. The transmitters selected for primary air flow and secondary air flow will be differential pressure transmitters that are accurate in the range of differential pressure developed by the flow elements.

(4) Primary and overfire air flow control. Figure 9-6 shows the primary and overfire air flow.

The firing rate demand signal serves as an index for air flow demand. The fuel feed signal and firing rate demand signal are cross limited by a high selector to serve as the setpoint for the total air flow controller. The output of the total air flow controller becomes the setpoint for the primary and overfire air flow controllers. The setpoint is characterized based on load to obtain the proper primary-to-overfire air flow ratio. The upper overfire air dampers are closed below 50 percent load.

The primary air controller setpoint is low limited by a minimum primary air setpoint. Each primary and upper air flow controller compares measured air flow to setpoint. The controller output becomes the demand to its respective air flow control damper.

All air flow measurements should be temperature corrected. Furnace exit gas temperature should be monitored and at high temperature alarmed to allow the operator to make the proper air flow adjustment to bring the temperature back to normal. A bias adjustment normally is provided for each controller.

(5) Furnace bed inventory control and solids

cooler temperature, air flow and spray water con-

trol. Furnace bed inventory control requires removal of excess bed material from the furnace. The solids cooler cools the excess bed material to a temperature which allows it to be disposed of via the ash system. Solids are removed from the furnace either by operator action or automatically on high furnace plenum pressure. The furnace bed static pressure, total furnace differential pressure,

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furnace plenum static pressure and lower furnace differential are all monitored to give the operator an indication that the furnace bed inventory should be reduced. When a sequence for removal of materials is initiated the solids cooler air flow control dampers are opened to a preset position.

The air flow dampers position will start a cycle timer and open the bed material transfer line. At the end of the timed period the transfer line is closed.

The material is cooled by spray water and air flow to a temperature suitable for the ash system. The spray water valve opens and closes automatically based on cooler bed temperature. After the bed material is cooled it is placed in a hopper for removal by the ash system. The air flow dampers and solid spray water valve can be opened and closed manually by a hand auto station. Figure 9-7 shows the solids cooler temperature and flow control.

(6) J-valve blower control. The J-valve blower control maintains air flow for fluidization and transport of material from the hot cyclone to the furnace. The J-valve control is shown on figure 9-

8. The system includes J-valve blower dischargepressure control valve, upleg aeration and plenum

TM 5-810-15

control valve and downleg aeration and plenum control valves.

(a) J-valve pressure control. The J-valve blower pressure is maintained by sensing pressure downstream of the J-valve blower discharge damper. The discharge damper is modulated to maintain a constant pressure of approximately

170”. The upleg and downleg plenum air is maintained at a constant value of approximately 400 lb/hr. The setpoint is constant throughout the load range. Upleg and downleg plenum air flow will be measured with a Venturi section or air foil flow element in the ductwork to the plenums. The flow element will be designed to provide a design differential pressure across the flow element of not less than 2 inches wg.

(b) J-valve aeration valve control. The measured air flow is compared to the constant setpoint and the control dampers modulated to maintain the air flow at setpoint. The downleg static pressure, inlet static pressure, and upleg static pressure outlet as well as differential pressure across portions of the J-valve indicate solids flow, density and dipleg differential are measured and are utilized to allow the operator to manually control

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9-9

TM 5-810-15

9-10

the aeration valves. The aeration control is normally only required during start-up and are manually controlled.

(7) Sorbent (limestone) feeder control.

The sorbent feeder control provides the proper

2 the combustion process. The sorbent feeder control is shown in figure 9-9. Sorbent feeder speed controls the sorbent flow to the combustor. The volumetric rate of sorbent delivered to the combustor is directly related to feeder speed.

air temperature at the burner outlet to the selected temperature. A low limit select limits the fuel to the available primary air flow through the duct burner.

When in-bed lances are utilized the fuel flow setpoint is compared to the actual fuel flow to modulate the burner valve. Position of the fuel valve is limited by a low selector to the available air flow to the combustor. The warmup burner and inbed lance control is shown in figure 9-10.

i. Oxygen trim. Boiler efficiency can be improved by minimizing excess air levels. Excess air

2 flue gases, modified by oxygen in the flue gas, total fuel flow and a correction factor. The SO

2 measurement is provided by a flue gas analyzer or analyzers, total fuel flow is taken from the main actual sorbent (limestone) flow. A low limit is is required to ensure complete combustion and optimum heat release from the fuel. However excess air adds to heat loss and reduces boiler oxygen analyzer is installed to monitor the amount of oxygen in the boiler flue gas. The signal from the analyzer is used to correct the combustion air flow fuel feeders and oxygen from the flue gas O

2 analyzer. The setpoint value is compared to the applied to the controller output to prevent the value from falling below a minimum value.

(8) Warmup burner control. A gas/oil fired burner or in-bed lances are utilized to warm the bed material to the value where main fuel combustion occurs. When gas/oil fire burners are utilized they normally are placed in the primary air duct. Fuel flow is regulated by a controller comparing primary to maintain the proper oxygen level in the flue gas exiting the boiler. The boiler manufacturer

*s recommendations for flue gas oxygen content versus boiler load for optimum boiler efficiency should be used to establish the proper oxygen content in the flue gas at all boiler loads. Oxygen trim controls applied to a parallel metering system

TM 5-810-15

are shown in figure 9-11. The oxygen setpoint is calculated from boiler load by a characterizing function generator applied to steam flow. Signal limiters are used to establish minimum and operation. The system must be made to comply with the appropriate NFPA regulations and the recommendations of the boiler manufacturer.

(2) Purging and interlocks. The specific purgmaximum corrections to the fuel/air ratio since major excursions are possible due to malfunctions of the oxygen analyzer. Automatic oxygen trim controls should not be used on stoker fired units.

ing and interlock requirements will depend on whether the boiler is gas/oil fired, stoker fired, pulverized coal fired or ACFB fired. Regardless of the type of firing system, certain functions must be

Since the fuel bed on a stoker cannot be increased or decreased quickly the firing rate on a stoker is varied primarily by changes in combustion air flow.

Changes in combustion air flow will cause similar changes in flue gas oxygen content. Automatic included in the furnace safety system. These functions include a prefiring purge of the furnace, establishment of permissives for fuel firing, emerand a post firing purge. Pulverized coal, ACFB and oxygen trim would attempt to correct the air flow and would cause unstable operation during load changes. Stoker fired units should be provided with manual oxygen trim.

9-3. Boiler controls.

gas/oil firing require additional functions such as establishment of permissives for firing the ignition system and continuous monitoring of firing conditions. The prefiring purge is required to ensure that all unburned fuel accumulated in the furnace is completely removed and is accomplished by passing a minimum of 25 to 30 percent air flow through the furnace for five minutes. The

a. Furnace safety system.

(1) General requirements. The main function of a furnace safety system is to prevent unsafe conditions to exist in the boiler including prevention of the formation of explosive mixtures of fuel and air in any part of the boiler during all phases of conditions that would cause an emergency shutdown (trip) for pulverized coal, gas/oil and

ACFB boilers are shown in table 9-2. The furnace safety system can be either deenergize-to-trip to

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TM 5-810-15

energize-to-trip. The energize-to-trip philosophy is more desirable since it reduces nuisance trips, is operable on loss of power, and is more reliable.

(3) Flame detection and management. Stoker fired boilers do not utilize flame detection or flame management. Pulverized coal and gas/oil fired systems do require flame detection, which is the key to proper flame management. The basic re-

Regardless of the level of automation incorporated into the burner controls, the system logic must insure that the operator commands are performed in the correct sequence with intervention only when required to prevent a hazardous condition.

Pulverized coal burner controls must provide the proper sequential logic to completely supervise burner startup and operation including coal feeders, quirements of flame detectors are detection of the high energy zone of a burner flame, ability to pulverizers, air registers, ignitors, and flame detectors. Gas/oil burner controls must provide the distinguish between ignitor and main flames, and discrimination between the source flame, adjacent flames, and background radiation. Ultraviolet (UV) detectors are suited for flame detection of gas or light oil ignitor and main gas flames. Infrared (IR) proper sequential logic to completely supervise burner startup and operation including gas/oil fuel valves, air registers, ignitors and flame detectors.

burner or gas lances and ignitor system to warm the detectors are used for pulverized coal flames. Self checking or redundant detectors should be used to ensure reliability. Location of the flame detectors is critical to proper flame management and must be boiler and bed temperature above minimum required for solid fuel firing. This burner operation is identical to a gas/oil burner operation. The

ACFB boiler does not have a main fuel burner; given careful consideration. Flame detection systems will be on-off type based on the presence or absence of flame.

(4) Burner controls. Burner controls are the permissives, interlocks, and sequential logic which are required for safe startup and operation of pulverized coal, ACFB and gas/oil burners. Burner controls range from manual to fully automatic.

however, the introduction of fuel is completely supervised to provide the proper sequence for purge, ignitors, warm-up burners, flame detection, coal feeders, sorbent feeders and bed temperature monitoring. Note the bed temperature monitor insures that adequate temperature is present to ignite the solid fuel. Adequate bed temperature

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TM 5-810-15

Table 9-2. Emergency Trip for Boilers.

Item Pulverized Coal Gas/Oil ACFB

Loss of all FD fans

Loss of all ID fans (if used)

High-low drum level

High steam pressure

X

X

X

X

X

X

X

X

X

X

X

X

High furnace pressure or draft

Low air flow

X

X

X

X

X

X

Loss of power to safety system

Flame failure

Gas or oil pressure/temperature out of limits

High cyclone level

X

X

X

X

X

X

All solids fuel feeders trip

Bed temperature greater than maximum

Bed temperature less than minimum

Emergency trip pushbutton

Trips recommended by boiler supplier

X

X

X

X

X

X

X

X

X

X

X

9-13

TM 5-810-15

allows a hot restart which bypasses the purge, ignitors and warm burners and allows the introduction of solid fuel provided certain conditions are met. Figure 9-12 shows sequential logic for burner control.

b. Feedwater flow and drum level control.

(1) Two element control. Two element feedwater control systems as shown in figure 9-13(a) are characterized by the use of steam flow as a feed-forward signal to reduce the effect of shrink and swell of the boiler drum level during load changes. Without the steam flow feed-forward signal, load changes will momentarily cause the drum level to change in a direction opposite to the load change. The feed-forward signal provides the correct initial response of the feedwater valve.

(2) Three element control. Three element feedwater control as shown in figure 9-13(b) uses feedwater flow in addition to steam flow to improve drum level control. In this system feedwater

9-14

CANCELLED

TM 5-810-15

flow to the boiler is metered and the feedwater valve is positioned by summing steam flow and drum level error through a controller. This system should be used when multiple boilers are connected to a common feedwater supply system since feedwater flow is a metered feedback signal and the control system demands a feedwater flow.

(3) System selection. Table 9-3 summarizes the types of feedwater control systems and the parameters which should be used for selection of the proper system.

c. Furnace pressure controls.

(1) Single element control. Furnace pressure

CANCELLED inlet vanes or adjustable speed drive for ID fan.

The control loop shown in figure 9-14 also uses a feed-forward demand signal that is representative

Table 9-3. Feedwater Control System Selection Guide

Control System

Two-element

Three-element

Boiler Requirements

Steady-State Swinging

Load Load

X X

X

Multiple

Boiler

X

9-15

TM 5-810-15

of boiler air flow demand. This feed-forward signal may be fuel flow, boiler master, or other demand index, but will not be a measured air flow signal.

(2) Furnace implosion protection. Boilers that have a large capacity and large draft losses due to air quality control equipment may require ID fans with a head capacity large enough to exceed design pressure limits of the furnace and ductwork. If this possibility exists, the furnace pressure control system must include furnace implosion protection.

The furnace implosion protection system will comply with the guidelines established by NFPA

85G. These guidelines include redundant furnace pressure transmitters and transmitter monitoring system, fan limits or run-backs on large furnace draft error, feed-forward action initiated by a main fuel trip, operating speed requirements for final control elements, and interlock systems.

d. Steam controls.

(1) Steam pressure control. Steam pressure is controlled by boiler firing rate. As discussed in combustion control, steam pressure is used to establish the master demand signal that controls fuel and combustion air flow.

(2) Steam flow control. Steam flow is a function of boiler load demand. Steam flow is also a function of fuel Btu input and can be used to trim combustion air flow as discussed in combustion control. Steam flow is also used to calculate boiler load for use in oxygen trim controls and as a feedforward signal in feedwater controls.

(3) Steam temperature control. Boilers that produce saturated steam do not require steam temperature controls. Boilers that produce superheated steam require a control loop to maintain superheater outlet temperature. A single element loop with feedback as shown in figure 9-15 is normally adequate for control of steam temperature.

e. Blowdown controls.

(1) Continuous blowdown. Continuous blowdown is the continuous removal of concentrated water from the boiler. The rate of blowdown is controlled by manually adjusting the setting of the of automatic blowdown will be dependent on whether blowdown heat is to be recovered and a

f. Sootblower control. Sootblower control continuous blowdown control valve. Continuous blowdown can be used on boilers of any capacity and permits heat recovery of the blowdown. The use of continuous blowdown heat recovery is dependent upon life cycle cost evaluation.

(2) Automatic blowdown. Automatic blowdown systems as shown in figure 9-16 continuously monitor the boiler water and adjust the rate of blowdown to maintain the conductance of the boiler water at the proper level. Control action can be two-position or modulating. The use should be an operator-initiated automated sequence control. After the start command the system should step through the sequence for all sootblowers including opening the valve for the sootblowing medium, timing the length of the blow and closing the valve. The system should automatically move to the next sootblower and continue the sequence until all sootblowers have been completed.

9-4. Nonboiler controls.

a. Low pressure steam controls.

9-16

(1) Turbine drives. The boiler feed pump turbine drive is controlled by feedwater header pressure. The steam control valve on the turbine drive inlet is controlled by a pressure transmitter on the feedwater header acting through a controller as shown in figure 9-17. The setpoint pressure will be lower than the normal operating feedwater pressure to prevent turbine drive operation during normal operating conditions.

(2) Sootblowers. Sootblower steam controls are normally a pressure control system to maintain the proper steam pressure at the sootblower inlet.

If remote indication of the sootblower steam header pressure is desired a transmitter and controller will be used as shown in figure 9-18(a). If remote indication is not required a pressure controller mounted on the control valve can be used as shown in figure 9-18(b).

(3) Steam coil air heater. The steam coil air heater controls are based on maintaining the flue gas leaving the air heater above the acid dew point temperature. This is accomplished by using an average cold end temperature control system as shown in figure 9-19. Air heater average inlet air temperature and average gas outlet temperature are calculated. These two signals are averaged to arrive at the average cold end temperature, which is used to control the steam coil control valve. Also, the control system should include an interlock that opens the steam coil control valve 100 percent when the ambient air is below a set temperature, usually 35 degrees F.

TM 5-810-15

(4) Deaerator. The DA steam controls are a pressure control system to maintain DA pressure.

A single element loop with feedback as shown in figure 9-20 is adequate for controlling DA pressure.

(5) Feedwater heater. The feedwater heater controls as shown in figure 9-21 are used to protect the economizer against acid condensation. The economizer outlet gas temperature and economizer inlet feedwater temperature are averaged. The average is used to control the feedwater temperature by regulating the steam input to the feedwater heater.

CANCELLED

9-17

TM 5-810-15

9-18

(2) Three element control. A three element

DA level control system as shown in figure 9-22(b) uses a metered condensate flow feedback signal in a cascaded control loop. This system will maintain

DA level on units that operate under swinging load conditions.

c. Pump recirculat ion control. Pump recirculation controls are necessary to maintain the minimum flow through a pump when required by the manufacturer. A breakdown orifice plate sized to pass the required minimum flow can be installed in a line from the pump discharge to the pump suction source. Since this system is a constant recirculation type, it is a source of lost pump hp. The lost hp can be eliminated by using automatic pump recirculation controls. This system requires pump

CANCELLED requirement. Automatic recirculation control will be used only when justified by LCCA evaluation.

b. Deaerator level controls.

(1) Two element control. A two element DA level control system as shown in figure 9-22(a) uses feedwater flow as a feedwater signal to make the system responsive to load changes. A two element system for DA level control can be used for most multiple unit installations that operate under steady load conditions.

9-5. Control panels.

a. Control room. A control room isolated from the plant environment complete with heating and air conditioning should be provided for all boiler plants. The boiler panels and auxiliaries may be located at the boiler front for packaged boilers up to 70,000 pph and for stoker fired units. A recorder panel should be located in the control room. The

TM 5-810-15

control room will be located at a central location in the plant to allow operating personnel good access to the boilers and the auxiliary equipment. The control room will be large enough for the operator interface for the boiler and auxiliaries and also allow room for a desk to be used by operating personnel.

tion with other I/O racks and the central control console. Redundant communication links should be provided to allow communication when one link is lost. All field wiring entering or leaving the I/O racks is to be connected to terminal blocks with spare terminals provided. The equipment in the 110 racks will be designed for installation in a dusty atmosphere with maximum ambient temperatures of 50 degrees C.

b. Operator interface. The operator interface to the boiler and auxiliaries may be via CRT

*s and printer housed in a control console or operator stations, recorders, indicators, annunciators and

(b) Operator interface. The control console will include the appropriate number of CRT

*s and start/stop controls mounted on a control panel.

(1) Distributed control system. Operator interprinters required by the size and complexity of the system. A minimum of two CRT

*s and two printers should be installed. The CRT

*s and keyboard or face via CRT and printers are normally used on larger units and are part of the distributed control system. This system should always utilize redundant microprocessors, ORT

*s and printers. The system will automatically switch to the back-up system and annunciate failure of a component. The system will be utilized to perform combustion control, data acquisition and trending, boiler effiother means of operation will be mounted in a console which allows the operators to access and

(c) Auxiliary panel. Auxiliary panel construction must conform to the requirements of the

National Electrical Code, the National Fire Protecciency calculations, graphic displays, boiler control motor start/stop and ash system controls. An auxiliary panel will also be required to mount critical controls and monitoring equipment.

(a) I/O racks. The system will include remote mounted input/output racks with redundant microprocessors for control. The information at the

I/O rack will be multiplexed to allow communication Association, and NEMA standards. It will be constructed of steel plate with adequate internal reinforcement to maintain flat surfaces and to provide rigid support for the instrumentation to be installed. The panel interior will have adequate bracing and brackets for mounting of equipment to be installed within the panel. Electrical outlets will be provided in the panel. No pressure piping of

9-19

9-20

TM 5-810-15

balancing for transfer; and have antireset windup characteristics. Operator stations with set point will process fluids is to be run in control panels. All field wiring entering or leaving control panels is to be connected to terminal blocks with spare termiindicate set point in engineering units. Operator nals provided. The items to be mounted in the stations with ratio or bias are to indicate the auxiliary panel will include hardwired main fuel trip magnitude of the ratio or bias at all times. Operator

(MFT) pushbutton, fan trips, drum level indication, stations are to indicate the measured variable on a soot blower controls and annunciation of critical continuously in engineering units and will indicate items. The annunciator should include items listed station output continuously in percent. The below.

indications on a station should be consistent with

1. Main fuel trip (MFP) all other stations such that all final control elements

2. Drum level high-low.

move closed to open from zero to 100 percent. For

3. Furnace pressure high.

hardwired operator stations, the position of final

4. Boiler FW pressure low.

control elements will not change when an operator

5. Control system power failure.

station is disconnected from or reconnected to its

(2) Panel mounted control system. The plug-in cable. Changes in ratio or bias settings will control and auxiliaries panel where used will not cause a process upset.

include operator stations, recorders, indicators,

(2) Records. Records will be kept for the paequipment start-stop controls and annunciation.

rameters indicated in table 9-4. Records will be

The arrangement of the panel will not be addressed stored on floppy disks when a control console is here since panel arrangements are normally based used. The operator will have access through the on the preferences of operating personnel and

CRT to display trends for parameter for which management.

records are kept. When the operator interface

(a) Control panel construction. Control utilizes boiler and auxiliaries panels recorders will panel construction must conform to the be used. Recorders may be strip chart recorders or requirements of the National Electrical Code, the circular chart recorders. The recorders will have

National Fire Protection Association, and NEMA scale markings consistent with the measured varistandards. Panels will be constructed of steel plate ables and associated field transmitters. The use of with adequate internal reinforcement to maintain circular chart recorders will be restricted to steam flat surfaces and to provide rigid support for the pressure, steam flow, air flow, and exit gas teminstrumentation to be installed. The panel interior perature. Circular chart recorders will not be used will have adequate bracing and brackets for when conservation of panel space is critical or mounting of equipment to be installed within the desirable. Allowances should be made to provide panel. A walk-in door for access to the panel spare pens for future use.

interior will be provided on both ends of the panel

(3) Indicators. Indicators will be provided for where possible and on at least one end of the panel.

the parameters shown in table 9-4. When a control

Electrical outlets will be provided in the panel. No console is utilized the parameter will be displayed pressure piping of process fluids is to be run in on the CRT. The display may be digital or graphic control panels. All field wiring entering or leaving and the displays should have scale markings control panels is to be connected to terminal blocks with spare terminals provided.

c. Instrumentation requirements. The boiler and auxiliaries panel or control console will provide

CANCELLED equipment in the steam plant. This will include operator interface to stations, recorders or trending, indication, equipment start/stop controls, and consistent with the measured variable and associated field transmitter. When indicators are located on a panel the indicators may be digital indicators or analog indicators. Digital indicators will have Light Emitting Diode (LED) uniplaner numerals, zero instrument zero drift with time, and

0.1 percent Full Scale (FS) or less span drift per year. Analog indicators will have vertical edgewise scales, plus or minus 2 percent full scale accuracy, annunciation. Table 9-4 summarizes the instruand scale markings consistent with the measured mentation requirements for the operator interface.

variable and the associated field transmitter.

(1) Operator stations. Operator stations are to

Integrators are shown in table 9-4 and should be provided as shown in table 9-4. Operator include the signal converters necessary to provide stations on control consoles will be accessed scaled integrated readings. Integrators will have at through the CRT or through individual operator least six digit readout.

station on control panels. Hand automatic operator

(4) Equipment start/stop controls. Equipment stations will provide bumpless transfer from hand start/stop controls will be provided for all major to automatic and automatic to hand without manual

TM 5-810-15

equipment as shown in table 9-4. Start/stop controls on a control console will be performed utilizing the ORT. Indication of motor operation should be indicated on the CRT. Start/stop controls will be indicating control switches or indicating push button when boiler and auxiliary panels are used for the operator interface.

(5) Annunciator. Annunciators will be provided on the boiler and auxiliaries panel for visual and audible indication of alarm conditions. Annunciator windows will have alarm legends etched on the windows and will be backlighted in alarm or test state. Each window will have at least two parallel connected bulbs and front access for ease of bulb replacement. All annunciator circuits will be solid state and compatible with microprocessor based controls. The annunciator will have an adjustable tone and volume horn. Split windows will be avoided unless conservation of panel space is critical. The annunciator system will have one of the alarm sequences specified in Instrument Society of America (ISA) S18.1. Test and acknowledge pushbuttons will be provided on the panel. All alarms, except for critical alarms, will be displaced on the ORT and printed on the printer when CRT

*s are utilized as the operator interface.

d. Ash handling control for stoker, pulverized coal and ACFB boilers.

(1) General requirements. Control of the fly ash system will be from the control room via ORT or control panel. A bottom ash panel will be located near the boilers. The control of the bottom ash system may also be controlled from the control

(4) Annunciation. Alarm conditions of the ash handling system should be audible and visually annunciated in the control room. Annunciation may be via CRT and printer or a panel mounted annunciator of the same type described in c(5) above.

f. Air quality control system for stoker, pulverized coal and ACFB boilers.

(1) General requirements. Control of the air quality control equipment will be from the control room via CRT or control panel. The operator interface will contain all devices required to control and monitor the operation of the air quality control system. This will include start/stop controls, selector controls, indication and annunciation.

(2) Start-stop controls. Start/stop controls will be provided for manual operation of baghouse cleaning via the CRT or panel mounted control switches.

(3) Selection controls. Selection controls will be provided for selection of manual, pressure initiated, or time sequenced baghouse cleaning. Operation of compartment isolation dampers and baghouse bypass dampers will be provided. The control will be via CRT or panel mounted selector switches.

(4) Indication. Indication will be provided for compartment pressures and temperatures, baghouse inlet pressures and temperatures, and baghouse outlet pressures and temperatures. The indication will be via CRT or panel mounted indicators.

(5) Annunciation. Alarm conditions of the air quality control system should be audible and room. The operator interface will contain all devices required to properly control and monitor the operation of the ash handling system. This will include start/stop control, selector controls, indicavisually annunciated in the control room. Annunciation may be via CRT and printer or a panel mounted annunciator as described in c(5) above.

g. Continuous emissions monitoring systems

tion, and annunciator.

(2) Start/stop controls. Controls will include

controls. The continuous emissions monitoring system (CEMS) controls will be located in an air start/stop controls for the vacuum producing equipment, initiation of system operation, emergency stop, selection of manual or automatic system operation and manual operation of hopper valves and vibrators. This control may be through a CRT conditioned and heated environment. The controls will be microprocessor based and include all printers, displays and equipment necessary to save

Malfunction of equipment will be annunciated in or panel mounted indicating control switches or indicating pushbuttons, pushbuttons and selector the control room.

9-6. Field Instrumentation.

switches.

(3) Indicators. Indication of system vacuum, primary and secondary bag filter pressures and temperature and vacuum pumps inlet temperature,

a. General. Transmitters, control drives, control valves and piping instrumentation will be provided valve position, bag filter operation, system operation and hopper being emptied should be displayed in the control room. The display may be via CRT or panel mounted indicators and indicating lights.

to sense the process variables and allow the control system to position the valves and dampers to control the process. All field devices shall be designed to operate in a dust laden atmosphere with temperature conditions varying from 20 to

160 degrees F.

9-21

TM 5-810-15

b. Field transmitters.

(1) General. Electronic transmitters should produce a 4-20 mA dc signal that is linear with the measured variable. Electronic transmitters will be the two wire type except when unavailable for a particular application. Encapsulated electronics are unacceptable in any transmitter. Transmitters will be selected such that the output signal represents a calibrated scale range that is a standard scale range between 110 and 125 percent of the maximum value of the measured process variable.

Transmitters will be designed for the service required and will be supplied with mounting brackets. Purge meters and differential regulators will be used on transmitters for boiler gas service or coal-air mixture service. A change in the load on a transmitter within the transmitter load limits will not disturb the transmitted signal. The load limits of the transmitter will be a minimum of 600 ohms.

Transmitters can be supplied with local indicators, either integral or field mounted, if desired.

Transmitters used for distributed control systems should be the “smart” type which have duplex digital communications ability transparent to the analog signal. Smart transmitters may be remotely calibrated via a hand held terminal. Data available at the hand held terminal should include programmed instrument number, instrument ID or serial number, instrument location, date of last calibration, calibrated range and diagnostics.

(2) Flow transmitters. Numerous types of flow transmitters are available. These include differential pressure with square root extractor, turbine

(4) Pressure transmitters. Measuring elements for pressure transmitters will be diaphragm, bellows, bourdon tube, or strain gage transducers.

Pressure transmitters will be accurate within 0.5

percent of span with ambient temperature effect not to exceed 1.0 percent of span per 100 degrees F variation. Measuring elements for pressure differential transmitters will be diaphragm, bellows, or sealed pressure capsule. Pressure differential transmitters will be accurate within 0.25 percent of span with ambient temperature effect not to exceed

1.0 percent of span per 100 degrees F variation.

Output signals for pressure and pressure differential transmitters will be linear with the sensed pressure or differential pressure.

(5) Temperature sensors. Several types of sensors can be used for temperature measurement.

Thermocouples sense temperature by a thermoelectric circuit which is created when two dissimilar metals are joined at one end. A wide variety of thermocouples are available for temperature sensing. Type J (iron-constantan) and type K (chromelalumel) are the most common types of thermocouples for boiler plant applications. Type J thermocouples can be used for temperatures from

32 to 1382 degrees F. Type K thermocouples can be used for temperatures from -328 to 2282 degrees F. The type of thermocouple to be used,

Type J or Type K, will be selected based upon the temperatures to be sensed. All thermocouples in the boiler plant will be of the same type. Resistance

Temperature Detectors (RTD) sense temperature based upon the relationship between the resistivity flowmeters, nutating disk type transmitter, ultrasonic flow transmitters, and magnetic flowmeters.

The most common method for measuring flow is to measure differential pressure across an orifice, flow of a metal and its temperature. The most common

RTD used in boiler plant applications is a platinum

RTD with a resistance of 100 ohms at 0 degrees C.

Sealed bulb and capillary sensors detect nozzle, venturi, pitot tube, or piezometer ring.

Square root extraction is necessary to linearize the temperature by sensing the change in volume due to changes in temperature of a fluid in a sealed output signal. Differential pressure measurement should be used for most steam plant flow applications. Nutating disk with pulse to 4-20 mA transmitters are normally used for fuel oil flow measurement. Flow transmitters will be accurate within system.

(6) Temperature transmitters. Measuring elements for temperature transmitters should be

Temperature transmitters will be accurate within

0.5 percent of span from 20 to 100 percent span with ambient temperature effect not to exceed 1.0

percent per 100 degrees F variation.

(3) Level transmitters. Measuring elements for level transmitters will be diaphragm, bellows, bourdon tube, strain gage transducer, caged float, or sealed pressure capsule. Level transmitters will be accurate within 0.5 percent of span with ambient temperature effect not to exceed 1.0 percent of span per 100 degrees F variation. The output signal will be linear with the sensed level.

0.5 percent of span with ambient temperature effect not to exceed 1.0 percent of span per 100 degrees

F degree variation. Output signals for temperature transmitters will be linear with the sensed temperature.

(7) Oxygen analyzers. Oxygen analyzers will be direct probe type utilizing an in situ zirconium sensing element. The element will be inserted directly into the gas stream and will directly contact the process gases. The sensing element will be provided with a protective shield to prevent direct

9-22

TM 5-810-15

impingement of fly ash on the sensing element. The analyzer should be equipped to allow daily automatic calibration checks without removing the analyzer from the process. The cell temperature in the analyzer will be maintained at the proper temperature by a temperature controller. The analyzer will be certified for “in stack” analysis technique in accordance with the Factory Mutual

(FM) approval guide. The analyzer will be furnished with all accessories necessary for a complete installation.

(8) Opacity monitors. Opacity monitors use the principal of transmissometry to indicate level of particulate emissions. A beam of light is projected across the flue gas stream and a detector registers variations in the light transmittance caused by the particulate in the flue gas.

(9) Flue gas monitors. Flue gas monitors will be provided for all items required for EPA reports.

Flue gas monitors are either in situ or extractive. In situ monitors are attached directly to the stack or breeching and access for maintenance should be provided. Extractive systems are wet, dry or diluted. Wet extractive system sample line should be heated to avoid corrosion. Dry systems utilize a cooler to remove water. Dilution systems utilize clean dry air to dilute the sample eliminating the need to heat the sample lines or dry the sample.

Either in situ or extractive flue gas monitors should be used and not a mixture of the two for the various gases to be analyzed. All analyzers should be provided with self calibration features and have contact outputs for control room annunciation.

have positioners with characterizable cams. Open/ shut control drives should have internally mounted four-way solenoid valves. Control drives will be designed to provide the rated torque with a maximum 50 psig air supply. The control drive will be sized to provide 150 percent of the torque required to drive controlled device.

(2) Electric control drives. Electric control drives will consist of an electric motor, gear box, rigid support stand, and wiring termination enclosure. Electric control drives will be weatherproof.

The gear box will be dust tight, weather tight, and totally enclosed. Electric control drives will be selflocking on loss of control or drive power. Drives for outdoor installation will be designed to operate with ambient conditions of -20 degrees F and a 40 miles per hour wind. Drives will have adjustable torque limit switches and position limit switches.

Electric drives will be supplied with motor starters, position controllers, speed controllers, characterizable positioners, transformers, and other accessories as required. The control drive will be sized to provide 150 percent of the torque required to drive the controlled device.

d. Control valves.

(1) Valve bodies. Control valve bodies will be constructed in accordance with the applicable

ANSI codes. Control valves will be globe type unless otherwise required for the particular process.

Butterfly valves may be used in low pressure water systems. Globe valves will have a single port designed to meet the design conditions. Restricted ports should be used when necessary for stable

c. Control drives. Control drives will be used for positioning of control dampers, isolating dampers, and other devices requiring mechanical linkages.

Control drives may be pneumatic or electric and are regulation at all loads. Special consideration will be given to valves which pass flashing condensate to assure adequate port and body flow area. The valve body size may be smaller than the line size if the either open-shut type or modulating type depending on the application. Modulating drives may include plug guide is sufficiently rugged to withstand the increased inlet velocity, but valve body size will not position transmitters. Control drives will have adjustable position limit switches wired to terminal blocks, handwheels or levers for manual operation, hand locks or be self locking, position indicators, and adjustable limit stops at maximum and be smaller than one half the line size. End preparations will be suitable for the applicable piping system. Valves will have teflon packing for joints will be flanged and bolted type and designed minimum positions. Drive arms and connecting linkages will be supplied with the damper drives.

Control drives will have stroking times as required by the service and by NFPA recommendations.

(1) Pneumatic control drives. Pneumatic control drives should consist of a double acting air cylinder with rigid support stand and weatherproof enclosure. Pneumatic control drives for outdoor service will have thermostat controlled space heaters installed and wired to terminal blocks. Pneumatic control drives for modulating service will for easy disassembly and assurance of correct valve stem alignment. Valve trim will be cage guided and removable through the top after bonnet removal.

Seat rings will be easily replaceable. Flow direction should be flow opening unless otherwise required.

(2) Valve operators. Control valve operators will be pneumatic diaphragm actuated type except where piston actuators are required. Valve operators will be adequate to handle unbalanced forces that occur from flow conditions or maximum differential. Allowances for stem force based on seating

9-23

TM 5-810-15

surface will be made to assure tight seating.

Diaphragms will be molded rubber and diaphragm housing will be pressed steel. Piston operators will use cast pistons and cylinders with 0-ring seals.

Each valve operator will have an air supply pressure filter regulator. Valve operators for modulating service valves in fast response control loops, such as flow control or pressure control, will have electropneumatic valve positioners. Limit switches will be provided if needed for remote indication or control logic.

(3) Control valve sizing. Proper control valve sizing requires careful analysis of the process and piping system in which each valve is to be used. It is necessary to calculate the required valve flow coefficients based upon flow, valve inlet pressure, valve outlet pressure, and process fluid conditions.

Calculations will be based on ISA S75.01. Valve flow coefficients will be calculated at the maximum, intermediate, and minimum process flow conditions. The control valves will be selected such that the maximum flow coefficient occurs at a valve travel between 70 and 80 percent. The minimum flow coefficient will occur at a valve travel between

10 and 20 percent. Control valves will be selected with a flow characteristic which provides uniform control loop stability over the range of process operating conditions. A quick opening flow characteristic provides large changes in flow at small valve travels and should primarily be used for on-off service applications. With a linear flow characteristic, the flow rate is directly proportional to valve travel. Valves with linear flow

(4) Control valve stations. Control valve stations are used to install control valves in piping systems and to provide a means of isolating and bypassing the control valve for maintenance purposes. Control valve stations will conform to the recommendations of ISA RP 75.06. Control valve stations consist of a control valve, isolating valves, bypass valve, and bypass line. Since control valves are normally smaller than the line size, reducers are required and can be integral to the control valve on valves with butt weld end connections. Isolation valves are required to isolate the control valve for repair, removal, or calibration and will be installed on the inlet and outlet sides of the control valve.

Isolation valves will be gate valves or other nonthrottling type valves. A bypass valve is necessary to provide a means of controlling the process when the control valve is not operable. The bypass valve will be identical to the control valve except it will be manually operated. Using an identical valve on the bypass provides better control during manual operation since the valve will have the proper flow coefficient and special valve trim. The bypass line which contains the bypass valve must be smaller than the main line size. The bypass line may be the same size as the bypass valve but in no case will the bypass line be smaller than one half the main line size.

e. Piping instrumentation.

(1) Pressure switches. Pressure switches are used to monitor pressures for remote indications, interlocking functions, and alarm conditions. Pressure switches may have snap acting switch contacts characteristics will be used for liquid level control where the ratio of the maximum valve pressure differential to the minimum valve pressure differential is less than five to one. Linear flow or mercury switch contacts. Shutoff valves of the same pressure and temperature rating as the process piping will be provided on each switch for isolation purposes. Snubbers will be provided on characteristic valves will also be used for pressure control of compressible fluids and for flow control switches when the pressure connection is located within 15 pipe diameters of a pump or compressor when the flow rate varies but the valve pressure differential is constant. With an equal percentage flow characteristic, equal increments of valve travel produce equal percentage changes in the existing flow rate. Equal percentage flow characteristic discharge.

(2) Pressure gauges. Pressure gauges are used to provide local and remote indication of process the normal operating pressure is at approximately valves will be used for liquid level control when the ratio of the maximum valve pressure differential to the minimum valve pressure differential is greater than or equal to five to one. Equal percentage flow characteristic valves will also be used for pressure control of liquids and for flow control when the valve pressure differential varies but the flow rate is constant. Special inner valve trim characteristics are required on applications where flashing or cavitation exist in liquid service and for noise control in steam or gas service.

mid-scale. Shutoff valves of suitable rating will be provided on each gauge for isolation purposes.

Snubbers will be provided on gauges when the pressure connection is located within 15 pipe diameters of a pump or compressor discharge.

Siphons will be provided on pressure gauges for steam service. Pressure gauges will be provided on the discharge of all pumps and compressors, all boiler drums, all main process headers, and other locations as required to monitor equipment and process operation.

9-24

(3) Thermometers. Thermometers are used to provide local indication of process temperatures.

Thermometers are normally the bimetallic type for most applications. Scale ranges will be selected such that the normal operating temperature is at approximately mid-scale. Thermometers will be provided with thermowells so the thermometer sensing element is not inserted directly into the process. Thermowells will be designed to withstand the pressure, temperature, and fluid velocities of the process in which they are inserted. Thermowells installed in piping will be long enough to extend to approximately the pipe centerline. Thermowells will have extensions to clear insulation and lagging.

(4) Thermocouples. Thermocouples are used to provide remote indication and control of process temperatures. Type J or Type K thermocouples are normally suitable for steam plant applications as discussed in paragraph 9-6b(5). Thermocouples will be provided with thermowells or protection tubes of suitable rating. Thermowell or protection tube length will be sufficient to provide the necessary insertion length plus the desired nipple length.

Thermocouple assemblies will also include insulators and terminal head with cover.

Table 9-4. Operator Interface Instrumentation Requirements.

TM 5-810-15

(5) Temperature switches. Temperature switches are used to monitor temperatures for remote indications, interlocking functions, and alarm conditions. Temperature switches may have snap acting switch contacts or mercury switch contacts and may be bulb and capillary type or direct insertion type. Thermowells of suitable rating will be supplied so the sensing element is not inserted directly into the process.

(6) Pressure controllers. Pressure controllers will be pneumatic with bourdon tube or bellows sensing element. The sensing element will be suitable for the pressure and temperature of the process fluid to be controlled and will be an integral part of the controller assembly. The sensing element will have adequate sensitivity and be able to withstand the maximum pressure under all conditions. Pressure controllers will have adjustable proportional and reset control action, control point adjustment, calibrated pressure setting dial, air supply filter regulator, and gauges which indicate air supply and controller output pressures. Pressure controllers will be mounted on the operator of the valve to be regulated.

Gas/Oil Fired Boilers Stoker Fired Boilers

Pulverized Coal Fired

Boiler

Operator Stations:

1. Boiler Master

2. Air Flow

3. Fuel flow

4. Drum Level

5. Oxygen Trim

6. Furnace Pressure

7. Steam Temperature

(SH only)

8. Deaerator

Pressure

9. Deaerator Level

R

X

X

R

X

R

X

X

1.

Boiler Master

2.

Air Flow

3.

Fuel Flow

4.

Drum Level

5.

Oxygen Trim

6.

Furnace Pressure

7.

Steam Temperature

(SH only)

8.

Deaerator

Pressure

9.

Deaerator Level

X

R

R

R

R

R

R

X

R

1.

Boiler Master

2.

Air Flow

3.

Pulverizer Master

4.

Pulverizers

5.

Primary Air

6.

Drum Level

7.

Oxygen Trim

8.

Furnace Pressure

9.

Steam Temperature

(SH only)

10. Deaerator Pressure

10. Feedwater Heater

Recorder Requirements:

1. Steam Pressure

X

R

X

X.

R

10. Feedwater Heater

11. Steam Coil

Preheater

1.

Steam Pressure

2.

Steam Flow

3.

Steam Temperature

(SH only)

X

R

R

R

R

11. Deaerator Level

12. Feedwater Heater

13. Steam Coil

Preheater

CANCELLED

1.

Steam Pressure

2.

Steam Flow

3.

Steam Temperature

(SH only)

R

X

R

R

R

R

2. Steam Flow

3. Fuel Flow

4. Drum Level

R 5. Percent Oxygen

6. Steam Temperature

(SH only)

7. Deaerator

Pressure

8. Deaerator Level

9. Feedwater Temp

10. Exit Gas Temp

11. Feedwater Flow

12. Air Flow

R

X

K

X

R

R

X

4.

Feedwater Flow

5.

Feedwater

Temperature

6.

Deserator

Pressure

7.

Deaerator Level

8.

Drum Level

9.

Air Flow

10. Percent Oxygen

11. Fuel Flow

R

X

K

X

R

R

R

K

4.

Feedwater Flow

5.

Feedwater

Temperature

6.

Deaerator

Pressure

7.

Deaerator Level

8.

Drum Level

9.

Total Air Flow

10. Percent Oxygen

11. Total Fuel Flow

R

X

X

K

R

R

R

K

R

X

R

R

R

R

R

R

X

R

9-25

TM 5-810-15

Table 9-4. Operator lnterface lnstrumentation Requirements. (Continued)

Gas/Oil Fired Boilers

Indicators:

1. Steam Pressure

2. Drum Level

3. Furnace Pressure

4. Combustion Air

Pressure

5. Exit Air

Pressures

6. Feedwater

Pressures

7. Feedwater

Temperature

8. FD Fan Amps

9. Boiler Feed Pump

Amps

10. Sootblower

Pressure

11. Gas Pressure

12. Oil Pressure

R

R

R

R

R

R

R

R

R

X

X

X

Stoker Fired Boilers

12. Combustion Air

Temperatures

13. Exit Gas

Temperatures

1.

2.

3.

4.

5.

6.

7.

8.

9.

Steam Pressure

Drum Level

Furnace Pressure

Combustion Air

Pressures

ExitGas

Pressure

Feedwater

Pressures

Feedwater

Temperature

ID Fan Amps

FD Fan Amps

10. Boiler Feed Pump

Amps

11. Sootblower

Pressure

X

R

R

R

R

R

R

R

R

R

R

R

K

Pulverized Coal Fired

Boiler

12 Combustion Air

Temperatures

13. Exit Gas

1.

Steam Pressure

2.

Drum Level

3.

Furnace Pressure

4.

Combustion Air

Pressures

5.

ExitGas

Pressures

6.

Feedwater

Pressures

7.

Feedwater

Temperature

8.

Pulverizer Outlet

Temperature

9.

ID Fan Amps

10. FD Fan Amps

11. PA Fan Amps

12. Boiler Feed Pump

Amps

13. Sootblower

Pressure

Integrators:

1. Steam Flow

2. Fuel Flow

3. Feedwater Flow

Equipment start-stop controls:

1. FDFans

2. Boiler Feed Pumps

X

X

X

R

R

1. Steam Flow

2. Fuel Flow

3. Feedwater Flow

1.

ID Fans

2.

FD Fans

3.

Boiler Feed Pumps

X

X

K

R

R

R

1. Steam Flow

2. Fuel Flow

3. Feedwater Flow

1.

IDFans

2.

FD Fans

3.

PA Fans

4.

Boiler Feed Pumps

5.

Pulverizers

6.

Coal Feeders

ACFB Fired Boilers

Indicators:

1. Furnace pressure R 23.

Fuel flow R

2. J-valve outlet static pressure

3. J-valve inlet static pressure

4. J-valve discharge pressure

5. Over furnace bed static pressure

R 24.

Sorbent (limestone) flow

25.

Steam temperature

R 26.

Furnace exit gas temperature

R 27.

Solids cooler stripper

R section temperature

28.

Solids cooler cooler

R

R

R

R

R

6. Furnace plenum pressure

7. Steam pressure

8. Spray water pressure

9. J-valve dipleg (diff press)

10. J-valve density (duff press)

11. Valve solids flow

R

R

K

R

29.

30.

cooler section temperature

J-valve fluid temperature

Furnace bed individual TC temperature

R 31.

Furnace bed average

R temperature

R

X

R

(diff press)

12. Bed differential pressure

13. Total furnace differential pressure

14. Primary air flow

15. Overfire air flow

32.

Furnace plenum temperature

R 33.

Feedwater temperature

R 34.

Oxygen

35.

SO

2

R 36.

Drum level

R 37.

Deasrator pressure

R

K

R

R

R

X

R

R

R

R

R

R

X

X

X

R

R

R

R

R

R

R

R

R

R

R

R

R

X

X

R

9-26

Table 9-4. Operator lnterface lnstrumentation Requirements. (Continued)

ACFB Fired Boilers

16. J-valve plenum air flow upleg

17. J-valve plenum air flow downleg

18. Total air flow

19. Steam flow

20. Spray water flow

21. Feedwater flow

22. Gas flow

Operator Stations:

1. Boiler master

2. Primary air flow

3. Overfire air flow

4. Oxygen trim

5. Fuel master

6. Fuel flow

7. Airflow

8. Furnace pressure

9. FD fan discharge pressure

10. Stripper cooler air flow

11. Solids cooler spray water

12. J-valve blower discharge pressure

13. J-valve aeration control

X

R

R

R 38.

Deaerator level

39.

Cyclone level (uses diff

R press transmitters)

40.

Chute air flow

R

R

R 14.

J-valve plenum air control

R 15.

Sorbent (limestone) feed

R 16.

Furnace bed inventory

R control

X 17.

Drum level

R 18.

Steam temperature (SH only)

R 19.

Warm-up burner control

R 20.

Deaerator pressure

R 21.

Deaerator level

R 22.

Feedwater heater

R 23.

Steam coil preheater

R

R

Recorder Requirements:

1. Furnace pressure pressure

3. J-valve inlet static pressure

4. J-valve discharge pressure

5. Over furnace bed static pressure

6. Furnace plenum pressure

7. Steam pressure

8. Spray water pressure

9. J-valve diplet (duff press)

10. J-valve density (duff press)

11. Valve solids flow

(diff press)

12. Bed differential pressure

13. Total furnace differential pressure

R 29.

J-valve fluid temperature

30.

Furnace bed individual TC

R temperature

R' 31.

Furnace bed average

R temperature

32.

Furnace plenum temperature

R 33.

Finish SH inlet temperature

R 34.

Feedwater temperature

X 35.

Oxygen

R 36.

SO[sub]2

R 37.

Drum level

R 38.

Deaerator pressure

39.

Deaerator level

R 40.

Cyclone level (uses duff

R press transmitters)

41.

FD fan discharge pressure

14. Primary air flow

15. Overfire air flow

16. J-valve plenum air flow upleg

17. J-valve plenum air flow

R 42.

Solids cooler stripper

R

R 44.

airflow

R 43.

Solids cooler solids air

CANCELLED

R

R

R downieg

18. Total air flow

19. Steam flow

20. Spray water flow

R

X

45.

Warmup burner discharge temperature

R 46.

Air heater inlet air temperature

R

R

R

21. Feedwater flow R 47.

Air heater gas temperature R

R

R 22. Gas flow

23. Fuel flow

24. Sorbent (limestone) flow

25. Steam temperature

26. Furnace exit gas temperature

27. Solids cooler stripper section temperature

28. Solids cooler cooler section temperature

R 48.

Air heater cold end

R temperature

R 49.

ID fan amps

R 50.

FD fan amps

R 51.

Boiler feed pump amps

R 52.

Sootblower pressure

R

R

X

R

R

R

R

X

R

R

X

X

R

R

X

X

R

X

R

R

R

R

R

X

R

X

R

R

R

R

R

TM 5-810-15

9-27

TM 5-810-15

Integrator

1. Steam flow

2. Fuel flow

3. Feedwater flow

4. Sorbent flow

R - Required

X - Optional

Table 9-4. Operator lnterface Instrumentation Requirement. (Continued)

ACFB Fired Boilers

Equipment Start-Stop Controls

R 1.

ID fans

R 2.

R 3.

R 4.

5.

FD fans

PA fans

Boiler feed pumps

Coal feeders

6.

7.

Sorbent (limestone) feeders

-valve blowers

R

R

R

R

R

R

R

9-28

CANCELLED

TM 5-810-15

CHAPTER 10

ELECTRIC SYSTEMS

This chapter addresses the criteria for the electric power system in a steam plant.

a. Design requirements. The electrical requirements for the steam plant are the same as those for the steam generating equipment of an electric power generating station as covered by TM 5-811-6.

b. The following sections of chapter 4 of TM 5-811-6 are applicable to the design of the steam boiler plant electrical requirements:

(1) Station service power system (section VL). Station service power systems for a 200,000 pph boiler addition is about the equivalent to a 20,000 kw power plant steam turbo-generator addition. Steam generators of 200,000 pph and above will require a 4.16 kv auxiliary bus to supply the larger motors— particularly boiler draft fans. Boilers below 200,000 pph can be accommodated with a 480 volt power supply.

(2) Emergency power system (section VII). Emergency power system applies to the steam boiler plant with the exception that the battery requirements will be less because the system will not be required to supply emergency power to any lube oil pumps.

(3) Motors (section VIII). This section covers the motor requirements to be used in the steam boiler plant design.

(4) Communication systems (section IX). This section covers the communication system requirements to be used in the steam boiler plant design.

CANCELLED

10-1

TM 5-810-15

APPENDIX A

REFERENCES

Part 1910: Occupational Safety and Health Standards

Government Publications.

29 CFR 1910

Department of the Army.

AR 420-49

TM 5-805-1

TM 5-805-4

TM 5-805-9

TM 5-809-1

TM 5-809-10

TM 5-810-1

TM 5-811-6

TM 5-815-1

TM 5-848-3

Heating, Energy Selection and Fuel Storage, Distribution, and Dispensing Systems

Standard Practice for Concrete Military Structures

Noise Control for Mechanical Equipment

Power Plant Acoustics

Load Assumptions for Buildings

Seismic Design for Buildings

Mechanical Design/Heating, Ventilating and Air

Conditioning

Electric Power Plant Design

Air Pollution Control Systems Boilers and Incinerators

Ground Storage of Coal

Non-Government Publications.

American Association of State Highway and Transportation Officials, (AASHTO)

444 North Capital Street, N.W., Suite 249

Washington, DC 20001

American Boiler Manufacturers Association (ABMA)

950 N. Glebe Road, Suite 160

Arlington, VA 22203

American Concrete Institute (ACI)

P. 0. Box 19150, Redford Station

Detroit, MI 48219-0150

ACI 301

ACI 318

(1989) Structural Concrete for Buildings

(1989; Rev 1992; Errata) Building Code Requirements for

Reinforced Concrete

American Gear Manufacturers Association (AGMA)

1500 King Street, Suite 201

Alexandria, VA 22314

American National Standards Institute, Inc. (ANSI)

11 West 42nd Street

New York, NY 10036

ANSI B20.1

(1990) Safety Standards for Conveyors and Related

CANCELLED

50 F Street, N.W., Suite 7702

Washington, DC 20001

American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE)

Publication Dept.

1791 Tullie Circle, N.E.

Atlanta, GA 30329

ASHRAE (1991) Handbook, HVAC Applications

ASHRAE (1992) Handbook, HVAC Systems and Equipment

ASHRAE (1993) Handbook, Fundamentals

ASHRAE (1990) Handbook, Refrigeration Systems and Applications

A-1

A-2

TM 5-810-15

American Society of Mechanical Engineers (ASME)

22 Law Drive

Box 2300

Fairfield, NJ 07007.2300

Boiler and Pressure Vessel Code, and Interpretations:

ASME Section I: Power Boilers (1992; Addenda Dec 1992)

ASME 08 Section VIII: Pressure Vessels, Division 1 (1992;

Addenda Dec 1992)

ASME B31.1

ASME B31.8

(1992; b31.la) Power Piping

(1992) Gas Transmission and Distribution Piping Systems

American Society for Testing and Materials (ASTM)

1916 Race Street

Philadelphia, PA 19103

ASTM A 36

ASTM A 48

ASTM A 536

ASTM A 588

(1991) Structural Steel M-Grades

(1990) Gray Iron Castings

(1984) Ductile Iron Castings

(1991a) High-Strength Low-Alloy Structural Steel with

ASTM D 395

ASTM D 1192

ASTM D 1857

ASTM D 2234

50 ksi (345 MPa) Minimum Yield Point to 4 in. (100 mm) Thick

(1988) Ferritic Ductile Iron Pressure-Retaining Castings for Use at Elevated Temperature

(1970; R 1977) Equipment for Sampling Water and Steam

(1989) Test Method for Fusibility of Coal and Coke Ash

(1989) Test Methods for Collection of a Gross Sample of

Coal

ASTM D 3174 (1989) Test Method for Ash in the Analysis Sample of

Coal and Coke from Coal

ASTM D 3176 (1989) Practice for Ultimate Analysis of Coal and Coke

Anti-Friction Bearing Manufacturers Association (AEBMA)

1101 Connecticut Ave., NW, Suite 700

Washington, DC 20036

Boiler Law and Rules and Regulations

The Bureau of Safety and Regulation

7150 Harris Drive

P 0 Box 30015

Lansing, MI 48909

Conveyor Equipment Manufacturers Association (CEMA)

932 Hungerford Dr., No. 36

Rockville, MD 20850

Factory Mutual Engineering and Research (FM)

1151 Boston-Providence Turnpike

P0 Box 9102

Norwood, MA 02062-9957

CANCELLED

Cleveland, OH 44115-2851

Hydraulic Institute (HI)

9 Sylvan Way, Suite 180

Parsippany, NJ 07054-3802

Instrument Society of America (ISA)

P.O. Box 3561

Durham, NC 27702

ISA S18.1

ISA S75.01

ISA RP 75.06

(1979; R1992) Annunciator Sequences and Specification

(1985) Control Valve Sizing Equations

(1981) Control Valve Manifold Designs

TM 5-810-15

Manufacturers Standardization Society of the Valve and Fittings Industry (MSS)

127 Park Street, NE

Vienna, VA 22180

MSS SP-69 (1991) Pipe Hangers and Supports-Selection and Application

National Association of Corrosion Engineers (NACE)

P 0 Box 218340

Houston, TX 77218-8340

National Electric Code

P0 Box 9146

Quincy, MA 02269

National Electrical Manufacturers Association (NEMA)

2101 L St., NW

Washington, DC 20037

National Fire Protection Association (NFPA)

P.O. Box 9146

Quincy, MA 02269

NFPA 85G (1987) Prevention of Furnace Implosions in Multiple

Burner Boiler-Furnaces

Rubber Manufacturers Association

1400 K Street NW

Washington, DC 20005

CANCELLED

A-3

TM 5-810-15

GLOSSARY

AAP

Army Ammunition Plant

CaCO

3

C03 Calcium Carbonate

CaO

Calcium Oxide

AASHTO

American Association of State Highway and

Transportation Officials

CaSiO

3

Calcium Silicate

ACFB

Atmospheric Circulating Fluidized Bed

CEMA

Conveyor Equipment Manufacturers Association

ACI

American Concrete Institute

CEMS

Continuous Emissions Monitoring Systems

AEI

Architectural and Engineering Instructions

CFHE

Closed Feedwater Heat Exchangers

AEL

Allowable Emissions Limit

cfm

Cubic feet per minute

AFBMA

Anti Friction Bearing Manufacturers Association

CO

2

Carbon Dioxide

AGMA

American Gear Manufacturers Association

CPU

Central Processing Unit

Al 0

3

Aluminum Oxide

CR

Concentration Ratio

ANSI

American National Standards Institute

CRT

Cathode Ray Tube

APHA

American Public Health Association

Cu

Copper

AREA

American Railway Association Standards

CuNi

Copper Nickel

ASHREA

American Society of Heating, Refrigeration and Air

Conditioning Engineers

DA

Deaerator

ASME

DAS

American Society of Mechanical Engineers

Data Acquisition System

ASYM

EHE

American Society for Testing and Materials

BHN

BOD

BOOS

Brinell Hardness Number

CANCELLED

Burner Out of Service

External Heat Exchanger

EPA

Environmental Protection Agency

F

Fahrenheit

FAC

Free Available Chlorine

Btu

British thermal units

Fe

Iron

C

Centigrade

FeO

3

Ferric Oxide

Ca

Calcium

FD

Forced Draft

CAAA

Clean Air Act Amendments of 1990

FGD

Flue Gas Desulfurization

Glossary-1

TM 5-810-15

FGR

Flue Gas Recirculation

FM

Factory Mutual

fpm

Feet per minute

fps

Feet per second

FS

Full Scale

FT

Fluid Temperature

FW

Feedwater

gph

Gallons per hour

HEI

Heat Exchange Institute

HEMA

Heat Exchanger Manufacturers Association

HI

Hydraulics Institute

Hg

Mercury

hp

Horsepower

HRA

Heat Recovery Area

HY

Hemispherical Temperature

lb/ft

3

Pounds per cubic foot

LCCA

Life Cycle Cost Analysis

LEA

Low Excess Air

LED

Light Emitting Diode

LNB

Low NOx burner

LOI

Loss on ignition

LPG

Liquified Petroleum Gas

mA

Milliamp

MB

Million Btu

MFT

Main Fuel Trip

Mg

Magnesium

MgO

Magnesium Oxide

Na Si

O

3

Sodium Silicate

NaZ

Sodium Zeolite

NEMA

National Electrical Manufacturers Association

HVAC

Heat, Ventilating and Air Conditioning

NFPA

National Fire Protection Association

Potassium Oxide

kv

Thousand volt

lb

Pound

ID NO

ISA

NO

2

Induced Draft

IES

Illuminating Engineers Society

IR

Infrared

Instrument Society of America

Nitric Oxide

Nitrogen Dioxide

CANCELLED

Nitrous Oxide

NOx

Oxides of Nitrogen

IT

Initial Deformation Temperature

NPDES

National Pollutant Discharge Elimination System

NPSH

Net Positive Suction Head

NPSHA

Net Positive Suction Head Available

NPSHR

Net Positive Suction Head Required

Glossary-2

TM 5-810-15

0

2

Oxygen

RO

Reverse Osmosis

ROM

Run-of-mine

OFA

Overfire Air

rpm

OSHA

Occupational Safety and Health Act

Revolutions per minute

PA

Primary Air

RTD

Resistance Temperature Detector

PC

Personal Computer

scfm

Standard cubic feet per minute

PC

Programmable Controller

SCR

Selective Catalytic Reduction Silicon Controlled

Rectifier

PC

Pulverized Coal

SH

Superheat

PCB

Polychlorinated Biphenyl

SiO

2

Silica Dioxide

pcf

Pounds per cubic foot

SNCR

Selective Noncatalytic Reduction

piw

Pounds per inch width

SO

2

Sulfur Dioxide

pph

Pounds per hour

SSU

Saybolt Seconds Universal

ppi

Pounds per ply inch

ST

Softening Temperature

ppm

Parts per million

TDS

Total Dissolved Solids

psf

Pounds per square foot

TiO

2

Titanium Dioxide

psi tph

Pounds per square inch

Tons per hour

psig

TSS

Pounds per inch gauge

Total Suspended Solids

RA

RATA

RDF

Relative Accuracy

CANCELLED

Refuse Derived Fuel

UHMW

Ultra High Molecular Weight

UPS

Uninterruptable Power Supply

uv

Ultraviolet

RMA

Rubber Manufacturers Association

wg

Water gauge

Glossary-3

The proponent agency of this publication is the Office of the

Chief of Engineers, United States Army. Users are invited to send comments and suggested improvements on DA Form

2028 (Recommended Changes to Publications and Blank

Forms) to HQUSACE (CEMP-ET), WASH DC 20314-1000.

By Order of the Secretary of the Army:

Official:

DENNIS J. REIMER

General, United States Army

Chief of Staff

JOEL B. HUDSON

Acting Administrative Assistant to the Secretary of the Army

Distribution:

To be distributed in accordance with DA Form 12-34-E, Block 1685, requirements for TM 5-810-15.

TM 5-810-15

CANCELLED

U.S. G.P.O.:1995-386-731:290

CANCELLED

PIN: 061328-000

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